System for conversion of crude oil to petrochemicals and fuel products integrating delayed coking of vacuum residue

ABSTRACT

Process scheme configurations are disclosed that enable conversion of crude oil feeds with several processing units in an integrated manner into petrochemicals. The designs utilize minimum capital expenditures to prepare suitable feedstocks for the steam cracker complex. The integrated process for converting crude oil to petrochemical products including olefins and aromatics, and fuel products, includes mixed feed steam cracking and gas oil steam cracking. Feeds to the mixed feed steam cracker include light products and naphtha from hydroprocessing zones within the battery limits, recycle streams from the C3 and C4 olefins recovery steps, and raffinate from a pyrolysis gasoline aromatics extraction zone within the battery limits. Feeds to the gas oil steam cracker include gas oil range intermediates from the vacuum gas oil hydroprocessing zone. Furthermore, vacuum residue is processed in a delayed coker unit to produce coker naphtha, which is hydrotreated and passed as additional feed to aromatics extraction zone and/or the mixed feed steam cracker, and coker gas oil range intermediates as additional feed to the gas oil hydroprocessing zone.

RELATED APPLICATIONS

This application is a Continuation of U.S. patent application Ser. No.15/817,143 filed Nov. 17, 2017, which claims priority to U.S.Provisional Patent Application No. 62/424,883 filed Nov. 21, 2016, U.S.Provisional Patent Application No. 62/450,018 filed Jan. 24, 2017, andU.S. Provisional Patent Application No. 62/450,055 filed Jan. 24, 2017,the contents of which are incorporated herein by reference in theirentireties.

BACKGROUND OF THE INVENTION Field of the Invention

The inventions disclosed herein relate to an integrated process andsystem for converting crude oil to petrochemicals and fuel products.

Description of Related Art

The lower olefins (i.e., ethylene, propylene, butylene and butadiene)and aromatics (i.e., benzene, toluene and xylene) are basicintermediates which are widely used in the petrochemical and chemicalindustries. Thermal cracking, or steam pyrolysis, is a major type ofprocess for forming these materials, typically in the presence of steam,and in the absence of oxygen. Typical feedstocks for steam pyrolysis caninclude petroleum gases, such as ethane, and distillates such asnaphtha, kerosene and gas oil. The availability of these feedstocks isusually limited and requires costly and energy-intensive process stepsin a crude oil refinery.

A very significant portion of ethylene production relies on naphtha asthe feedstock. However, heavy naphtha has a lower paraffin and higheraromatics content than light naphtha, making it less suitable asfeedstock in the production of ethylene without upgrading. Heavy naphthacan vary in the amount of total paraffins and aromatics based on itssource. Paraffins content can range between about 27-70%, naphthenescontent can range between about 15-60%, and the aromatics content canrange between about 10-36% (volume basis).

Many chemicals producers are limited by the supply and quality of feedfrom nearby refiners due to reliance on oil refinery by-products asfeed. Chemicals producers are also limited by the high cost of oilrefining and its associated fuels markets, which may negativelyinfluence the economic value of refinery sourced feeds. Higher globalfuel efficiency standards for automobiles and trucks will reduce fuelsdemand and narrow refinery margins, and may complicate the economics offuels and chemicals supply and/or markets.

A need remains in the art for improved processes for converting crudeoil to basic chemical intermediates such as lower olefins and aromatics.In addition, a need remains in the art for new approaches that offerhigher value chemical production opportunities with greater leverage oneconomies of scale.

SUMMARY

In accordance with one or more embodiments, the invention relates to anintegrated process for producing petrochemicals and fuel product from acrude oil feed. The integrated process includes an initial separationstep to separate from a crude oil feed in an atmospheric distillationzone at least a fraction comprising straight run naphtha and lightercomponents, one or more middle distillate fractions, and an atmosphericresidue fraction. A vacuum gas oil fraction is separated from theatmospheric residue fraction in a vacuum distillation zone. In adistillate hydroprocessing (“DHP”) zone, such as a diesel hydrotreater,at least a portion of the middle distillates are processed to produce anaphtha fraction and a diesel fuel fraction. The vacuum gas oil fraction(and optionally all or a portion of an atmospheric gas oil fraction, orall or a portion of a heavy atmospheric gas oil fraction) is processedin a gas oil hydroprocessing zone to produce naphtha, middledistillates, and hydrotreated gas oil and/or unconverted oil.Hydrotreated gas oil and/or unconverted oil are processed in a gas oilsteam cracking zone.

The vacuum residue from the vacuum distillation zone is processed in adelayed coking zone. The delayed coking zone produces a coker naphthastream, a coker gas oil stream and petroleum coke. In certainembodiments, some or all of the coker gas oil stream is sent to a vacuumgas oil hydroprocessing zone. In certain embodiments, some or all of thecoker naphtha stream is sent to a coker naphtha hydrotreater.

The fraction(s) from the atmospheric distillation with straight runnaphtha and lighter components, and an aromatics extraction zoneraffinate, are processed in a mixed feed steam cracking zone. Theproducts from the mixed feed steam cracking zone and the gas oil steamcracking zone include integrated or separate mixed product stream(s)comprising H₂, methane, ethane, ethylene, mixed C3s and mixed C4s;pyrolysis gasoline stream(s); and pyrolysis oil stream(s).

From the mixed product stream(s) C3s and the mixed C4s, petrochemicalsethylene, propylene and butylenes are recovered. Ethane and non-olefinicC3s are recycled to the mixed feed steam cracking zone, and non-olefinicC4s are recycled to the mixed feed steam cracking zone or to a separateprocessing zone for production of additional petrochemicals. Pyrolysisgasoline is treated in a py-gas hydroprocessing zone to producehydrotreated pyrolysis gasoline. The hydrotreated pyrolysis gasoline isrouted to the aromatics extraction zone to recover aromatic products andthe aromatics extraction zone raffinate that is recycled to the mixedfeed steam cracking zone.

Still other aspects, embodiments, and advantages of these exemplaryaspects and embodiments, are discussed in detail below. Moreover, it isto be understood that both the foregoing information and the followingdetailed description are merely illustrative examples of various aspectsand embodiments, and are intended to provide an overview or frameworkfor understanding the nature and character of the claimed aspects andembodiments. The accompanying drawings are included to provideillustration and a further understanding of the various aspects andembodiments, and are incorporated in and constitute a part of thisspecification. The drawings, together with the remainder of thespecification, serve to explain principles and operations of thedescribed and claimed aspects and embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and withreference to the attached drawings in which the same or similar elementsare referred to by the same number, and where:

FIGS. 1 and 2 schematically depicts operations upstream of a steamcracker complex in embodiments of processes for producing petrochemicalsand fuel product;

FIG. 3 schematically depicts operations downstream of and including asteam cracker complex in embodiments of processes for producingpetrochemicals and fuel product;

FIG. 4 schematically depicts operations downstream of and including asteam cracker complex in embodiments of processes for producingpetrochemicals integrating metathesis;

FIG. 5 schematically depicts operations downstream of and including asteam cracker complex in embodiments of processes for producingpetrochemicals and fuel products integrating mixed butanol production;

FIG. 6 schematically depicts operations downstream of and including asteam cracker complex in embodiments of processes for producingpetrochemicals and fuel products integrating metathesis and mixedbutanol production;

FIGS. 7 and 8 schematically depict operations upstream of a steamcracker complex in further embodiments of processes for producingpetrochemicals and fuel product;

FIG. 9 schematically depicts a single reactor hydrocracking zone;

FIG. 10 schematically depicts a series-flow hydrocracking zone withrecycle;

FIG. 11 schematically depicts a two-stage hydrocracking zone withrecycle;

FIG. 12 schematically depicts a delayed coking zone with coker naphthahydrotreating;

FIG. 13 schematically depicts operations downstream of and including asteam cracker complex in further embodiments of processes for producingpetrochemicals and fuel product;

FIG. 14 schematically depicts operations in further embodiments ofprocesses for producing petrochemicals and fuel products integratingmetathesis; and

FIGS. 15 and 16 schematically depict operations upstream of a steamcracker complex in still further embodiments of processes for producingpetrochemicals and fuel product.

DESCRIPTION

Process scheme configurations are disclosed that enable conversion ofcrude oil feeds with several processing units in an integrated mannerinto petrochemicals. The designs utilize minimum capital expenditures toprepare suitable feedstocks for the steam cracker complex. Theintegrated process for converting crude oil to petrochemical productsincluding olefins and aromatics, and fuel products, includes mixed feedsteam cracking and gas oil steam cracking. Feeds to the mixed feed steamcracker include light products and naphtha from hydroprocessing zoneswithin the battery limits, recycle streams from the C3 and C4 olefinsrecovery steps, and raffinate from a pyrolysis gasoline aromaticsextraction zone within the battery limits. Feeds to the gas oil steamcracker include gas oil range intermediates from the vacuum gas oilhydroprocessing zone. Furthermore, vacuum residue is processed in adelayed coker unit to produce coker naphtha, which is hydrotreated andpassed as additional feed to aromatics extraction zone and/or the mixedfeed steam cracker, and coker gas oil range intermediates as additionalfeed to the gas oil hydroprocessing zone.

The phrase “a major portion” with respect to a particular stream orplural streams means at least about 50 wt % and up to 100 wt %, or thesame values of another specified unit.

The phrase “a significant portion” with respect to a particular streamor plural streams means at least about 75 wt % and up to 100 wt %, orthe same values of another specified unit.

The phrase “a substantial portion” with respect to a particular streamor plural streams means at least about 90, 95, 98 or 99 wt % and up to100 wt %, or the same values of another specified unit.

The phrase “a minor portion” with respect to a particular stream orplural streams means from about 1, 2, 4 or 10 wt %, up to about 20, 30,40 or 50 wt %, or the same values of another specified unit.

The term “crude oil” as used herein refers to petroleum extracted fromgeologic formations in its unrefined form. Crude oil suitable as thesource material for the processes herein include Arabian Heavy, ArabianLight, Arabian Extra Light, other Gulf crudes, Brent, North Sea crudes,North and West African crudes, Indonesian, Chinese crudes, or mixturesthereof. The crude petroleum mixtures can be whole range crude oil ortopped crude oil. As used herein, “crude oil” also refers to suchmixtures that have undergone some pre-treatment such as water-oilseparation; and/or gas-oil separation; and/or desalting; and/orstabilization. In certain embodiments, crude oil refers to any of suchmixtures having an API gravity (ASTM D287 standard), of greater than orequal to about 20°, 30°, 32°, 34°, 36°, 38°, 40°, 42° or 44°.

The acronym “AXL” as used herein refers to Arab Extra Light crude oil,characterized by an API gravity of greater than or equal to about 38°,40°, 42° or 44°, and in certain embodiments in the range of about38°-46°, 38°-44°, 38°-42°, 38°-40.5°, 39°-46°, 39°-44°, 39°-42° or39°-40.5°.

The acronym “AL” as used herein refers to Arab Light crude oil,characterized by an API gravity of greater than or equal to about 30°,32°, 34°, 36° or 38°, and in certain embodiments in the range of about30°-38°, 30°-36°, 30°-35°, 32°-38°, 32°-36°, 32°-35°, 33°-38°, 33°-36°or 33°-35°.

The acronym “LPG” as used herein refers to the well-known acronym forthe term “liquefied petroleum gas,” and generally is a mixture of C3-C4hydrocarbons. In certain embodiments, these are also referred to as“light ends.”

The term “naphtha” as used herein refers to hydrocarbons boiling in therange of about 20-205, 20-193, 20-190, 20-180, 20-170, 32-205, 32-193,32-190, 32-180, 32-170, 36-205, 36-193, 36-190, 36-180 or 36-170° C.

The term “light naphtha” as used herein refers to hydrocarbons boilingin the range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100,32-90, 32-88, 36-110, 36-100, 36-90 or 36-88° C.

The term “heavy naphtha” as used herein refers to hydrocarbons boilingin the range of about 90-205, 90-193, 90-190, 90-180, 90-170, 93-205,93-193, 93-190, 93-180, 93-170, 100-205, 100-193, 100-190, 100-180,100-170, 110-205, 110-193, 110-190, 110-180 or 110-170° C.

In certain embodiments naphtha, light naphtha and/or heavy naphtha referto such petroleum fractions obtained by crude oil distillation, ordistillation of intermediate refinery processes as described herein.

The modifying term “straight run” is used herein having its well-knownmeaning, that is, describing fractions derived directly from theatmospheric distillation unit, optionally subjected to steam stripping,without other refinery treatment such as hydroprocessing, fluidcatalytic cracking or steam cracking. An example of this is “straightrun naphtha” and its acronym “SRN” which accordingly refers to “naphtha”defined above that is derived directly from the atmospheric distillationunit, optionally subjected to steam stripping, as is well known.

The term “kerosene” as used herein refers to hydrocarbons boiling in therange of about 170-280, 170-270, 170-260, 180-280, 180-270, 180-260,190-280, 190-270, 190-260, 193-280, 193-270 or 193-260° C.

The term “light kerosene” as used herein refers to hydrocarbons boilingin the range of about 170-250, 170-235, 170-230, 170-225, 180-250,180-235, 180-230, 180-225, 190-250, 190-235, 190-230 or 190-225° C.

The term “heavy kerosene” as used herein refers to hydrocarbons boilingin the range of about 225-280, 225-270, 225-260, 230-280, 230-270,230-260, 235-280, 235-270, 235-260 or 250-280° C.

The term “atmospheric gas oil” and its acronym “AGO” as used hereinrefer to hydrocarbons boiling in the range of about 250-370, 250-360,250-340, 250-320, 260-370, 260-360, 260-340, 260-320, 270-370, 270-360,270-340 or 270-320° C.

The term “heavy atmospheric gas oil” and its acronym “H-AGO” as usedherein in certain embodiments refer to the heaviest cut of hydrocarbonsin the AGO boiling range including the upper 3-30° C. range (e.g., forAGO having a range of about 250-360° C., the range of H-AGO includes aninitial boiling point from about 330-357° C. and an end boiling point ofabout 360° C.).

The term “medium atmospheric gas oil” and its acronym “M-AGO” as usedherein in certain embodiments in conjunction with H-AGO to refer to theremaining AGO after H-AGO is removed, that is, hydrocarbons in the AGOboiling range excluding the upper about 3-30° C. range (e.g., for AGOhaving a range of about 250-360° C., the range of M-AGO includes aninitial boiling point of about 250° C. and an end boiling point of fromabout 330-357° C.).

In certain embodiments, the term “diesel” is used with reference to astraight run fraction from the atmospheric distillation unit. Inembodiments in which this terminology is used, the diesel fractionrefers to medium AGO range hydrocarbons and in certain embodiments alsoin combination with heavy kerosene range hydrocarbons.

The term “atmospheric residue” and its acronym “AR” as used herein referto the bottom hydrocarbons having an initial boiling point correspondingto the end point of the AGO range hydrocarbons, and having an end pointbased on the characteristics of the crude oil feed.

The term “vacuum gas oil” and its acronym “VGO” as used herein refer tohydrocarbons boiling in the range of about 370-550, 370-540, 370-530,370-510, 400-550, 400-540, 400-530, 400-510, 420-550, 420-540, 420-530or 420-510° C.

The term “light vacuum gas oil” and its acronym “LVGO” as used hereinrefer to hydrocarbons boiling in the range of about 370-425, 370-415,370-405, 370-395, 380-425, 390-425 or 400-425° C.

The term “heavy vacuum gas oil” and its acronym “HVGO” as used hereinrefer to hydrocarbons boiling in the range of about 425-550, 425-540,425-530, 425-510, 450-550, 450-540, 450-530 or 450-510° C.

The term “vacuum residue” and its acronym “VR” as used herein refer tothe bottom hydrocarbons having an initial boiling point corresponding tothe end point of the VGO range hydrocarbons, and having an end pointbased on the characteristics of the crude oil feed.

The term “fuels” refers to crude oil-derived products used as energycarriers. Fuels commonly produced by oil refineries include, but are notlimited to, gasoline, jet fuel, diesel fuel, fuel oil and petroleumcoke. Unlike petrochemicals, which are a collection of well-definedcompounds, fuels typically are complex mixtures of different hydrocarboncompounds.

The terms “kerosene fuel” or “kerosene fuel products” refer to fuelproducts used as energy carriers, such as jet fuel or other kerosenerange fuel products (and precursors for producing such jet fuel or otherkerosene range fuel products). Kerosene fuel includes but is not limitedto kerosene fuel products meeting Jet A or Jet A-1 jet fuelspecifications.

The terms “diesel fuel” and “diesel fuel products” refer to fuelproducts used as energy carriers suitable for compression-ignitionengines (and precursors for producing such fuel products). Diesel fuelincludes but is not limited to ultra-low sulfur diesel compliant withEuro V diesel standards.

The term “aromatic hydrocarbons” or “aromatics” is very well known inthe art. Accordingly, the term “aromatic hydrocarbon” relates tocyclically conjugated hydrocarbons with a stability (due todelocalization) that is significantly greater than that of ahypothetical localized structure (e.g., Kekule structure). The mostcommon method for determining aromaticity of a given hydrocarbon is theobservation of diatropicity in its 1H NMR spectrum, for example thepresence of chemical shifts in the range of from 7.2 to 7.3 ppm forbenzene ring protons.

The terms “naphthenic hydrocarbons” or “naphthenes” or “cycloalkanes”are used herein having their established meanings and accordinglyrelates to types of alkanes that have one or more rings of carbon atomsin the chemical structure of their molecules.

The term “wild naphtha” is used herein to refer to naphtha productsderived from hydroprocessing units such as distillate hydroprocessingunits, diesel hydroprocessing units and/or gas oil hydroprocessingunits.

The term “unconverted oil” and its acronym “UCO,” is used herein havingits known meaning, and refers to a highly paraffinic fraction from ahydrocracker with a low nitrogen, sulfur and Ni content and includinghydrocarbons having an initial boiling point corresponding to the endpoint of the AGO range hydrocarbons, in certain embodiments the initialboiling point in the range of about 340-370° C., for instance about 340,360 or 370° C., and an end point in the range of about 510-560° C., forinstance about 540, 550 or 560° C. UCO is also known in the industry byother synonyms including “hydrowax.”

The term “coker gas oil” and its acronym “CGO” are used herein to referto hydrocarbons boiling in the vacuum gas oil range derived from thermalcracking operations in a coker unit such as a delayed coker unit.

The term “heavy coker gas oil” and its acronym “HCGO” are used herein torefer to hydrocarbons boiling in the heavy vacuum gas oil range derivedfrom thermal cracking operations in a coker unit such as a delayed cokerunit.

The term “light coker gas oil” and its acronym “LCGO” are used herein torefer to hydrocarbons boiling in the light vacuum gas oil range derivedfrom thermal cracking operations in a coker unit such as a delayed cokerunit.

The term “coker naphtha” is used herein to refer to hydrocarbons boilingin the naphtha range derived from thermal cracking operations in a cokerunit such as a delayed coker unit.

The term “C# hydrocarbons” or “C#”, is used herein having its well-knownmeaning, that is, wherein “#” is an integer value, and meanshydrocarbons having that value of carbon atoms. The term “C#+hydrocarbons” or “C#+” refers to hydrocarbons having that value or morecarbon atoms. The term “C#-hydrocarbons” or “C#-” refers to hydrocarbonshaving that value or less carbon atoms. Similarly, ranges are also setforth, for instance, C1-C3 means a mixture comprising C1, C2 and C3.

The term “petrochemicals” or “petrochemical products” refers to chemicalproducts derived from crude oil that are not used as fuels.Petrochemical products include olefins and aromatics that are used as abasic feedstock for producing chemicals and polymers. Typical olefinicpetrochemical products include, but are not limited to, ethylene,propylene, butadiene, butylene-1, isobutylene, isoprene, cyclopentadieneand styrene. Typical aromatic petrochemical products include, but arenot limited to, benzene, toluene, xylene, and ethyl benzene.

The term “olefin” is used herein having its well-known meaning, that is,unsaturated hydrocarbons containing at least one carbon-carbon doublebond. In plural, the term “olefins” means a mixture comprising two ormore unsaturated hydrocarbons containing at least one carbon-carbondouble bond. In certain embodiments, the term “olefins” relates to amixture comprising two or more of ethylene, propylene, butadiene,butylene-1, isobutylene, isoprene and cyclopentadiene.

The term “BTX” as used herein refers to the well-known acronym forbenzene, toluene and xylenes.

The term “make-up hydrogen” is used herein with reference tohydroprocessing zones to refer to hydrogen requirements of the zone thatexceed recycle from conventionally integrated separation vessels; incertain embodiments as used herein all or a portion of the make-uphydrogen in any given hydroprocessing zone or reactor within a zone isfrom gases derived from the steam cracking zone(s) in the integratedprocesses and systems.

The term “crude to chemicals conversion” as used herein refers toconversion of crude oil into petrochemicals including but not limited tolower olefins such as ethylene, propylene, butylenes (includingisobutylene), butadiene, MTBE, butanols, benzene, ethylbenzene, toluene,xylenes, and derivatives of the foregoing.

The term “crude to chemicals conversion ratio” as used herein refers tothe ratio, on a mass basis, of the influent crude oil before desalting,to petrochemicals.

The term “crude C4” refers to the mixed C4 effluent from a steamcracking zone.

The term “C4 Raffinate 1” or “C4 Raff-1” refers to the mixed C4s streamleaving the butadiene extraction unit, that is, mixed C4s from the crudeC4 except butadiene.

The term “C4 Raffinate 2” or “C4 Raff-2” refers to the mixed C4s streamleaving the MTBE unit, that is, mixed C4s from the crude C4 exceptbutadiene and isobutene.

The term “C4 Raffinate 3” or “C4 Raff-3” refers to the mixed C4s streamleaving the C4 distillation unit, that is, mixed C4s from the crude C4except butadiene, isobutene, and butane-1.

The terms “pyrolysis gasoline” and its abbreviated form “py-gas” areused herein having their well-known meaning, that is, thermal crackingproducts in the range of C5 to C9, for instance having an end boilingpoint of about 204.4° C. (400° F.), in certain embodiments up to about148.9° C. (300° F.).

The terms “pyrolysis oil” and its abbreviated form “py-oil” are usedherein having their well-known meaning, that is, a heavy oil fraction,C10+, that is derived from steam cracking.

The terms “light pyrolysis oil” and its acronym “LPO” as used herein incertain embodiments refer to pyrolysis oil having an end boiling pointof about 440, 450, 460 or 470° C.

The terms “heavy pyrolysis oil” and its acronym “HPO” as used herein incertain embodiments refer to pyrolysis oil having an initial boilingpoint of about 440, 450, 460 or 470° C.

In general, the integrated process for producing petrochemicals and fuelproducts from a crude oil feed includes an initial separation step toseparate from a crude oil feed in an atmospheric distillation zone atleast a first atmospheric distillation zone fraction comprising straightrun naphtha; a second atmospheric distillation zone fraction comprisingat least a portion of middle distillates, and a third atmosphericdistillation zone fraction comprising atmospheric residue. A firstvacuum distillation zone fraction comprising vacuum gas oil is separatedfrom the third atmospheric distillation zone fraction in a vacuumdistillation zone. In a distillate hydroprocessing (“DHP”) zone, such asa diesel hydrotreater, at least a portion of the second atmosphericdistillation zone fraction is processed to produce at least a first DHPfraction and a second DHP fraction, wherein the first DHP fractioncomprises naphtha and the second DHP fraction is used for diesel fuelproduction. The first vacuum distillation zone fraction (and optionallyall or a portion of an atmospheric gas oil fraction, or all or a portionof a heavy atmospheric gas oil fraction) is processed in a gas oilhydroprocessing zone to produce naphtha, middle distillates, andhydrotreated gas oil and/or unconverted oil. Hydrotreated gas oil and/orunconverted oil are processed in the gas oil steam cracking zone.

The vacuum residue from the vacuum distillation zone is processed in adelayed coking zone. The delayed coking zone produces a coker naphthastream, a coker gas oil stream and petroleum coke. In certainembodiments, some or all of the coker gas oil stream is sent to a vacuumgas oil hydroprocessing zone. In certain embodiments, some or all of thecoker naphtha stream is sent to a coker naphtha hydrotreater.

At least the first atmospheric distillation zone fraction and apyrolysis gasoline raffinate from an aromatics extraction zone areprocessed in a mixed feed steam cracking zone. The products from themixed feed steam cracking zone and the gas oil steam cracking zoneinclude integrated or separate mixed product stream(s) comprising H₂,methane, ethane, ethylene, mixed C3s and mixed C4s; pyrolysis gasolinestream(s); and pyrolysis oil stream(s).

From the mixed product stream(s) C3s and the mixed C4s, petrochemicalsethylene, propylene and butylenes are recovered. Ethane and non-olefinicC3s are recycled to the mixed feed steam cracking zone, and non-olefinicC4s are recycled to the mixed feed steam cracking zone or to a separateprocessing zone for production of additional petrochemicals. Pyrolysisgasoline is treated in a py-gas hydroprocessing zone to producehydrotreated pyrolysis gas. The hydrotreated pyrolysis gasoline isrouted to the aromatics extraction zone to recover aromatic products andthe aromatics extraction zone raffinate that is recycled to the mixedfeed steam cracking zone.

Ethane and non-olefinic C3s and C4s are recovered, with ethane andnon-olefinic C3s recycled to the steam cracking complex, andnon-olefinic C4s recycled to the steam cracking complex or passed to aseparate processing zone for production of additional petrochemicalssuch as propylene and/or mixed butanol liquids. Pyrolysis gasoline istreated in a py-gas hydroprocessing zone to produce hydrotreatedpyrolysis gas, that is routed to an aromatics extraction complex torecover aromatic petrochemicals and a raffinate, including pyrolysisgasoline raffinate that is recycled to the steam cracking complex.

FIGS. 1, 2 and 3 schematically depict embodiments of processes andsystems for conversion of crude oil to petrochemicals and fuel products,including a mixed feed steam cracking zone, a delayed coking zone, and agas oil steam cracking zone. Generally, FIGS. 1 and 2 show operationsupstream of the mixed feed steam cracking zone (“MFSC”) 230 and the gasoil steam cracking zone 250 while FIG. 3 shows operations downstream ofthe crude oil conversion zone and including the mixed feed steamcracking zone 230 and the gas oil steam cracking zone 250. Theintegrated processes and systems include a vacuum gas oilhydroprocessing zone, which can operate as a vacuum gas oil hydrocracker320 as shown in FIG. 1 or as a vacuum gas oil hydrotreater 300 as shownin FIG. 2. The mixed feed steam cracking zone and the gas oil steamcracking zone are shown for simplicity in a single schematic block230/250 in FIGS. 3, 4, 5 and 6.

In the description herein, both the mixed feed steam cracking zone 230and the gas oil steam cracking zone 250 are collectively referred to asthe “steam cracker complex” 230/250 in certain instances, although aperson having ordinary skill in the art will appreciate that thedifferent steam cracking zones contain different furnaces and associatedexchangers, with certain products from each combined for furtherdownstream operations. In certain embodiments quench systems andfractionation units can be combined. In additional embodiments separatequench systems and fractionation units can be used for each of the mixedfeed steam cracking zone 230 and the gas oil steam cracking zone 250.

With reference to FIG. 1, a crude oil feed 102, in certain embodimentsAXL or AL, is separated into fractions in a crude complex 100, typicallyincluding an atmospheric distillation zone (“ADU”) 110, a saturated gasplant 150 and a vacuum distillation zone (“VDU”) 160. The crude oil feed102, in certain embodiments having LPG and light naphtha removed, isseparated into fractions in the atmospheric distillation zone 110. Asshown in FIG. 1, light products, for instance, light hydrocarbons withfewer than six carbons, are passed to a mixed feed steam cracking zone230. In particular, C2-C4 hydrocarbons 152 including ethane, propane andbutanes are separated from the light ends and LPG 112 from theatmospheric distillation zone 110 via the saturated gas plant 150.Optionally, other light products are routed to the saturated gas plant150, shown in dashed lines as stream 156, such as light gases fromrefinery units within the integrated system, and in certain embodimentslight gases from outside of the battery limits. The separated C2-C4hydrocarbons 152 are routed to the mixed feed steam cracking zone 230.Off-gases 154 from the saturated gas plant 150 and off-gases 208 fromthe mixed feed steam cracking zone 230 and gas oil steam cracking zone250 are removed and recovered as is typically known, for instance tocontribute to a fuel gas (“FG”) system.

Straight run naphtha 136 from the atmospheric distillation zone 110 ispassed to the mixed feed steam cracking zone 230. In certainembodiments, all, a substantial portion or a significant portion of thestraight run naphtha 136 is routed to the mixed feed steam cracking zone230. Remaining naphtha (if any) can be added to a gasoline pool. Inaddition, in certain embodiments the straight run naphtha stream 136contains naphtha from other sources as described herein and sometimesreferred to as wild naphtha, for instance, naphtha range hydrocarbonsfrom one or more of the integrated distillate, gas oil and/or residuehydroprocessing units.

Middle distillates are used to produce diesel and/or kerosene, andadditional feed to the mixed feed steam cracking zone 230. In theembodiments shown in FIG. 1, at least three different middle distillatecuts are processed for production of fuel products and petrochemicals(via the steam cracker). In one example using the arrangement shown inFIG. 1, a first atmospheric distillation zone middle distillate fraction116, in certain embodiments referred to as a kerosene fraction, containslight kerosene range hydrocarbons, a second atmospheric distillationzone middle distillate fraction 122, in certain embodiments referred toas a diesel fraction, contains heavy kerosene range hydrocarbons andmedium AGO range hydrocarbons, and a third atmospheric distillation zonemiddle distillate fraction 126, in certain embodiments referred to as anatmospheric gas oil fraction, contains heavy AGO range hydrocarbons. Inanother example using the arrangement shown in FIG. 1, a first middledistillate fraction 116 contains kerosene range hydrocarbons, a secondmiddle distillate fraction 122 contains medium AGO range hydrocarbonsand a third middle distillate fraction 126 contains heavy AGO rangehydrocarbons. In another example using the arrangement shown in FIG. 1,a first middle distillate fraction 116 contains light kerosene rangehydrocarbons and a portion of heavy kerosene range hydrocarbons, asecond middle distillate fraction 122 contains a portion of heavykerosene range hydrocarbons and a portion of medium AGO rangehydrocarbons and a third middle distillate fraction 126 contains aportion of medium AGO range hydrocarbons and heavy AGO rangehydrocarbons.

For example, a first middle distillate fraction 116 can be processed ina kerosene sweetening process 170 to produce kerosene fuel product 172,for instance, jet fuel compliant with Jet A or Jet A-1 specifications,and optionally other fuel products (not shown). In certain embodimentsherein, all or a portion of the first middle distillate fraction 116 isnot used for fuel production, but rather is used as a feed fordistillate hydroprocessing so as to produce additional feed for themixed feed steam cracking zone 230.

A second middle distillate fraction 122 is processed in a distillatehydroprocessing zone such as a diesel hydrotreating zone 180, to producewild naphtha 184 and a diesel fuel fraction 182, for instance, compliantwith Euro V diesel standards. In additional embodiments, all or aportion of the first middle distillate fraction 116 can be treated withthe second middle distillate fraction 122, as denoted by dashed lines.In further embodiments, the diesel hydrotreating zone 180 can alsoprocess distillate products from the vacuum hydroprocessing zone.

All or a portion of the wild naphtha 184 is routed to the mixed feedsteam cracking zone 230; any portion that is not passed to the mixedfeed steam cracking zone 230 can be routed to the gasoline pool. Incertain embodiments, the wild naphtha 184 is routed through the crudecomplex 100, alone, or in combination with other wild naphtha fractionsfrom within the integrated process. In embodiments in which the wildnaphtha 184 is routed through the crude complex 100, all or a portion ofthe liquefied petroleum gas produced in the diesel hydrotreating zone180 can be passed with the wild naphtha. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of thewild naphtha 184 is routed to the mixed feed steam cracking zone 230(directly or through the crude complex 100).

In certain embodiments (as denoted by dashed lines), all, a substantialportion, a significant portion or a major portion of the third middledistillate fraction 126 is routed to the vacuum gas oil hydroprocessingzone in combination with the vacuum gas oil stream 162; any portion thatis not passed to the vacuum gas oil hydroprocessing zone can be routedto the gas oil steam cracking zone 250 without hydroprocessing. Infurther embodiments (as denoted by dashed lines), all, a substantialportion, a significant portion or a major portion of the third middledistillate fraction 126 is routed to the gas oil steam cracking zone 250without hydroprocessing, and any portion that is not passed to the gasoil steam cracking zone 250 is routed to the vacuum gas oilhydroprocessing zone.

An atmospheric residue fraction 114 from the atmospheric distillationzone 110 is further separated in the vacuum distillation zone 160. Asshown, vacuum gas oil 162 from the vacuum distillation zone 160 isrouted to the vacuum gas oil hydroprocessing zone. In certainembodiments, a minor portion of the atmospheric residue fraction 114 canbypass the vacuum distillation zone 160 (not shown) and is routed to thedelayed coker unit 900.

In certain embodiments, all, a substantial portion, a significantportion or a major portion of the vacuum gas oil 162 is routed to thevacuum gas oil hydroprocessing zone. In certain embodiments, vacuum gasoil can bypass the vacuum gas oil hydroprocessing zone and be routed tothe gas oil steam cracking zone 250 (not shown). Any portion that is nothydroprocessed can be routed to the gas oil steam cracking zone 250. Incertain optional embodiments, in addition to vacuum gas oil andoptionally atmospheric gas oil, the vacuum gas oil hydroprocessing zonecan also process atmospheric and/or vacuum gas oil range products fromthe delayed coker unit 900. As shown in FIG. 1, vacuum gas oilhydroprocessing is with a vacuum gas oil hydrocracking zone 320 that canoperate under mild, moderate or severe hydrocracking conditions, andgenerally produces a hydrocracked naphtha fraction 326, a diesel fuelfraction 322, and an unconverted oil fraction 324. The diesel fuelfraction 322 is recovered as fuel, for instance, compliant with Euro Vdiesel standards, and can be combined with the diesel fuel fraction 182from the diesel hydrotreating zone 180. As shown in FIG. 2, vacuum gasoil hydroprocessing is with a vacuum gas oil hydrotreating zone 300 thatcan operate under mild, moderate or severe hydrotreating conditions, andgenerally produces a hydrotreated gas oil fraction 304, naphtha and somemiddle distillates. Naphtha range products can be separated fromproducts within the vacuum gas oil hydrotreating zone 300 as ahydrotreated naphtha stream 306. Alternatively, or in conjunction withthe hydrotreated naphtha stream 306, a cracked distillates stream 308containing hydrotreated distillates (and in certain embodiments naphtharange products) are routed to diesel hydrotreating zone 180 for furtherhydroprocessing and/or separation into diesel hydrotreating zone 180products.

In certain embodiments, all, a substantial portion, a significantportion or a major portion of the wild naphtha fraction from the vacuumgas oil hydroprocessing zone, streams 326 or 306, is routed to the mixedfeed steam cracking zone 230, alone, or in combination with other wildnaphtha fractions from within the integrated process; any portion thatis not passed to the mixed feed steam cracking zone 230 can be routed tothe gasoline pool. In certain embodiments, the wild naphtha fractionfrom the vacuum gas oil hydroprocessing zone is routed through the crudecomplex 100, alone, or in combination with other wild naphtha fractionsfrom within the integrated process. In embodiments in which the wildnaphtha fraction from the vacuum gas oil hydroprocessing zone is routedthrough the crude complex 100, all or a portion of the liquefiedpetroleum gas produced in the vacuum gas oil hydroprocessing zone can bepassed with the wild naphtha.

Heavy product from the vacuum gas oil hydroprocessing zone is routed tothe gas oil steam cracking zone 250. In the embodiments with the vacuumgas oil hydrotreating zone 300, heavy product is the hydrotreated gasoil fraction 304 that contains the portion of the vacuum gas oilhydrotreater 300 effluent that is at or above the AGO, H-AGO or VGOboiling range. In the embodiments with the vacuum gas oil hydrocrackingzone 320, heavy product is the unconverted oil fraction 324. In certainembodiments, in a mode of operation to maximize production of aromaticspetrochemicals, all, a substantial portion, a significant portion or amajor portion of heavy product from the vacuum gas oil hydroprocessingzone is routed to the gas oil steam cracking zone 250. In furtherembodiments, in a mode of operation to maximize production of lightolefinic petrochemicals, all, a substantial portion, a significantportion or a major portion of heavy product from the vacuum gas oilhydroprocessing zone is further processed in the vacuum gas oilhydroprocessing zone (cracked to extinction in VGO hydrocracking) so asto produce additional light products that are routed to the mixed feedsteam cracking zone 250.

An atmospheric residue fraction 114 from the atmospheric distillationzone 110 is further separated in the vacuum distillation zone 160.Vacuum gas oil 162 from the vacuum distillation zone 160 is routed tothe vacuum gas oil hydroprocessing zone. At least a major portion of avacuum residue fraction 168 from the vacuum distillation zone 160 ispassed to a delayed coking zone 900. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of thetotal vacuum residue 168 is routed to the delayed coking zone 900. Theremainder (if any) is routed to the fuel oil pool (not shown). Inaddition, in certain embodiments, a minor portion of the atmosphericresidue fraction 114 can bypass the vacuum distillation zone 160 (notshown) and be routed to the delayed coking zone 900. In certainembodiments, all or a portion of a pyrolysis oil stream 218 from thesteam cracker complex, for instance, shown as stream 902, can beprocessed in the delayed coking zone 900.

The delayed coking zone 900 (which includes a coker naphthahydrotreating zone) generally produces a hydrotreated coker naphthastream 908, a coker gas oil stream 904 and petroleum coke 910, which isrecovered. In certain embodiments, all, a substantial portion, asignificant portion or a major portion of the coker gas oil stream 904is passed to the gas oil hydroprocessing zone.

The coker naphtha, after hydrotreating, stream 908, can provideadditional feed to the aromatics extraction zone 620 and/or the mixedfeed steam cracker 230 and/or passed to a gasoline pool. In embodimentsin which the hydrotreated coker naphtha stream 908 is intended asadditional feed to the mixed feed steam cracker 230, it can optionallybe routed through the crude complex 100, alone, or in combination withwild naphtha fractions from within the integrated process. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of hydrotreated coker naphtha stream 908 (optionallyhaving C5s removed and routed to the mixed feed steam cracker 230 asdiscussed below) is routed to the to the aromatics extraction zone 620;any remainder can be passed to mixed feed steam cracker 230 and/or to agasoline pool. In certain embodiments, all, a substantial portion, asignificant portion or a major portion of hydrotreated coker naphthastream 908 is routed to the to the mixed feed steam cracker 230; anyremainder can be passed to aromatics extraction zone 620 and/or to agasoline pool. The stream can be routed to the mixed feed steam cracker230, even if there is aromatic content, for instance, if the demand forolefins is higher than for aromatics. In any event, certain aromaticcontent will remain and pass to the aromatics extraction zone 620 withpyrolysis gas from the steam cracker complex.

With reference to FIG. 3, the mixed feed steam cracking zone 230 and thegas oil steam cracking zone 250 operate to convert their respectivefeeds into ethylene 202, propylene 204, mixed C4s 206, pyrolysisgasoline 212, pyrolysis oil 218, and off-gases 208 that can be passed toan integrated fuel gas system. Further, hydrogen 210 is recovered fromthe cracked products and can be recycled to hydrogen users within thecomplex limits. Not shown are the ethane and propane recycle, which aretypical in steam cracking operations, although it is appreciated that incertain embodiments all or a portion of the ethane and propane can bediverted. In certain embodiments, all, a substantial portion, asignificant portion or a major portion of ethane is recycled to themixed feed steam cracking zone 230, and all, a substantial portion, asignificant portion or a major portion of propane is mixed feed steamcracking zone 230. In certain embodiments hydrogen for all hydrogenusers in the integrated process and system is derived from hydrogen 210recovered from the cracked products, and no outside hydrogen is requiredonce the process has completed start-up and reached equilibrium. Infurther embodiments excess hydrogen can be recovered.

For simplicity, operations in an olefins recovery train are not shown,but are well known and are considered part of the mixed feed steamcracking zone 230 and gas oil steam cracking zone 250 as describedherein with respect to FIGS. 3, 4, 5 and 6.

The mixed C4s stream 206 containing a mixture of C4s from the steamcracker complex 230/250, known as crude C4s, is routed to a butadieneextraction unit 500 to recover a high purity 1,3-butadiene product 502.A first raffinate 504 (“C4-Raff-1”) containing butanes and butenes ispassed to a selective hydrogenation unit (“SHU”) and methyl tertiarybutyl ether (“MTBE”) unit, SHU and MTBE zone 510, where it is mixed withhigh purity fresh methanol 512 from outside battery limits to producemethyl tertiary butyl ether 514.

A second raffinate 516 (“C4 Raff-2”) from the SHU and MTBE zone 510 isrouted to a C4 distillation unit 520 for separation into a 1-buteneproduct stream 522 and an alkane stream 524 (a third raffinate “C4Raff-3”) containing residual C4s, all, a substantial portion, asignificant portion or a major portion of which is recycled to the mixedfeed steam cracking zone 230 although it is appreciated that in certainembodiments all or a portion of the residual C4s can be diverted.Separation of the ethylene 202, propylene 204 and the mixed C4s stream206 occurs in a suitable arrangement of known separation steps forseparating steam cracking zone effluents, including compressionstage(s), depropanizer, debutanizer, demethanizer and deethanizer.

All, a substantial portion or a significant portion of the pyrolysisgasoline 212 from the steam cracker complex 230/250 is fed to a py-gashydrotreatment and recovery center 600/620. In certain embodiments,select hydrocarbons having 5-12 carbons are recovered from untreatedpyrolysis gasoline and the remainder is subsequently hydrotreated foraromatics recovery. In a py-gas hydrotreating unit, diolefins andolefins in the pyrolysis gasoline are saturated.

Hydrotreated pyrolysis gasoline from the py-gas hydrotreating unit (incertain embodiments having C5s removed and recycled to the mixed feedsteam cracking zone 230 instead of or in conjunction with C5s from thearomatics extraction zone 620) is routed to the aromatics extractionzone 620. The py-gas hydrotreating zone 600 and the aromatics extractionzone 620 are shown for simplicity in a single schematic block 600/620 inFIGS. 3, 4, 5 and 6.

The aromatics extraction zone 620 includes, for instance, one or moreextractive distillation units, and operates to separate the hydrotreatedpyrolysis gasoline into an aromatics stream 622 containing high-puritybenzene, toluene, xylenes and C9 aromatics, which are recovered forchemical markets. C5 raffinate 606 and non-aromatics 646 (for instance,C6-C9) are recycled to the mixed feed steam cracking zone 230. Incertain embodiments, all, a substantial portion or a significant portionof the C5 raffinate 644 and non-aromatics 646 are passed to the mixedfeed steam cracking zone 230. A heavy aromatics stream 642 (forinstance, C10-C12) can be used as an aromatic solvent, an octaneboosting additive or as a cutter stock into a fuel oil pool. In certainembodiments ethylbenzene 628 can be recovered.

In certain embodiments, pyrolysis oil 218 can be blended into the fueloil pool. In additional embodiments, pyrolysis oil 218 can be fractioned(not shown) into light pyrolysis oil and heavy pyrolysis oil. Forinstance, light pyrolysis oil can be blended with the first middledistillate stream 116 and/or the second middle distillate stream 122 toproduce diesel fuel product and/or additional feed to the mixed feedsteam cracking zone 230. In another embodiment light pyrolysis oilderived from pyrolysis oil 218 can be processed in the vacuum gas oilhydroprocessing zone. In additional embodiments, light pyrolysis oilderived from pyrolysis oil 218 can be blended into the fuel oil pool. Infurther embodiments, light pyrolysis oil derived from pyrolysis oil 218can be processed in the delayed coking zone 900. In certain embodiments,all, a substantial portion, a significant portion or a major portion oflight pyrolysis oil can be processed in the delayed coking zone 900.Heavy pyrolysis oil can be processed in the delayed coking zone 900,blended into the fuel oil pool, and/or used as a carbon black feedstock.In certain embodiments, all, a substantial portion, a significantportion or a major portion of the pyrolysis oil 218 (light and heavy)can be processed in the delayed coking zone 900.

FIG. 4 schematically depicts further embodiments of processes andsystems for conversion of crude oil to petrochemicals and fuel products,with metathesis conversion of C4 and C5 olefins to produce additionalpropylene. The process operates as described with respect to FIG. 1upstream of the steam cracking operations.

Downstream of the steam cracking operations, the butadiene extractiontrain can optionally operate in a manner similar to that in FIG. 3 shownas the third C4 raffinate stream 524 from a diverter (in dashed lines)from the C4 distillation unit 520 directly to the mixed feed steamcracking zone 230.

In a metathesis mode of operation, a mixed C4 raffinate stream 532 (“C4Raff 3”) from the C4 distillation unit 520 and C5 raffinate 540 from thepy-gas hydrotreatment and recovery center 600/620 are routed to ametathesis unit 530 for metathesis conversion to additional propylene534. In certain embodiments, all, a substantial portion, a significantportion or a major portion of the cracked C5s from the py-gashydrotreater can be routed to the metathesis unit 530 prior to aromaticsextraction. As indicated, a portion 536 of the ethylene product 202 canbe routed to the metathesis unit 530. In additional embodiments,ethylene for the metathesis unit 530 is supplied from outside thecomplex limits, instead of or in addition to the portion 536 of theethylene product 202.

Selective recovery of various alkene and diene pyrolysis chemicalshaving four carbons, and metathesis conversion to produce additionalpropylene, is achieved using a metathesis unit 530. A stream 538containing a mixture of mostly saturated C4/C5 from the metathesis unit530 is recycled to the mixed feed steam cracking unit 230.

As in FIG. 3, in the configuration of FIG. 4, pyrolysis gasoline 212from the steam cracker complex 230/250 is routed to the py-gashydrotreatment and recovery center 600/620; C6-C9 aromatics stream 622,BTX, is recovered for chemical markets; C6-C9 non-aromatics stream 646is recycled to the mixed feed steam cracking zone 230; and the heavyaromatics stream 642 (for instance, C10-C12 products) is recovered. Incertain embodiments ethylbenzene 628 can be recovered. In addition, in ametathesis mode of operation, a C5 raffinate is routed to the metathesisunit 530, shown as stream 540. Optionally C5 raffinate is recycled tothe mixed feed steam cracking zone 230 (as in the embodiments of FIG. 3)via stream 606, shown in dashed lines in FIG. 4. In certain embodiments(not shown), all or a portion of the cracked C5s from the py-gashydrotreater can be routed to the metathesis unit 530 prior to aromaticsextraction.

In the configuration depicted in FIG. 4, an optional diverter is shown,indicated as a diverter and stream in dashed lines, to bypass themetathesis conversion process, to therefore divert all, a substantialportion, a significant portion or a major portion of the third C4raffinate stream 524 to the mixed feed steam cracking zone 230. In ametathesis mode, flow can be directed to the metathesis conversion unit530. In further alternative modes, flow of the third C4 raffinate stream524 can be directed to the mixed feed steam cracking zone 230 and themetathesis conversion unit 530. In this manner, a producer can vary thequantity of feed to tailor the desired outputs. Accordingly, 0-100% ofthe third C4 raffinate stream 524 can be routed to the metathesisconversion unit 530, and the remainder (if any) is directed to the mixedfeed steam cracking zone 230. The quantity can be determined, forinstance, based upon demand for ethylene, demand for propylene, and/orminimum ranges for which the unit is operated depending on designcapacity.

FIG. 5 schematically depicts further embodiments of processes andsystems for conversion of crude oil to petrochemicals and fuel products.The process operates as described with respect to FIG. 1 upstream of thesteam cracking operations. In this embodiment, an additional step isprovided to convert a mixture of butenes into mixed butanols suitable asa gasoline blending oxygenate and for octane enhancement. Suitableprocesses to convert a mixture of butenes into mixed butanols aredescribed in one or more of commonly owned patent publicationsUS20160115107A1, US20150225320A1, US20150148572A1, US20130104449A1,US20120245397A1 and commonly owned U.S. Pat. Nos. 9,447,346B2,9,393,540B2, 9,187,388B2, 8,558,036B2, all of which are incorporated byreference herein in their entireties. In certain embodiments, aparticularly effective conversion process known as “SuperButol™”technology is integrated, which is a one-step process that converts amixture of butenes into mixed butanol liquids.

Downstream of the steam cracking operations, the butadiene extractiontrain can optionally operate in a manner similar to that in FIG. 3 shownas the stream 524 from a diverter (in dashed lines) from the C4distillation unit 520 directly to the mixed feed steam cracking zone230. A mixed butanols production zone 550 is integrated for selectiverecovery of various alkene and diene pyrolysis chemicals having fourcarbons, and in certain processing arrangements hydrating a portion ofthose C4's in a butanol production unit (such as a “SuperButol™” unit)to produce high value fuel additives.

For instance, the mixed butanols production zone 550 operates to convertbutenes to butanols from undervalued refinery/petrochemical mixed olefinstreams. The butanols provide an alternative option for oxygenates ingasoline blends. The crude C4 processing center 550 includes theconversion reaction of butenes to butanols, for instance, in one or morehigh pressure catalytic reactors followed by gravity separation ofbutenes and butanols from water, and subsequent separation of thebutanols product from butenes by distillation. Process stages includebutenes and water make-up and recycle, butanol reaction, high pressureseparation, low pressure separation, debutenizer distillation (productcolumn) and an aqueous distillation column.

FIG. 5 depicts embodiments in which a C4 raffinate stream 552 containingbutenes from the C4 distillation unit 520 routed to the mixed butanolsproduction zone 550 to convert the mixture of butenes into mixed butanolliquids 554. In certain embodiments, all, a substantial portion, asignificant portion or a major portion of stream 552 is routed to thebutanol production unit 550. Alkanes 556 are recycled to the mixed feedsteam cracking zone 230.

As in FIGS. 1 and 3 in the configuration of FIG. 5, pyrolysis gasoline212 from the steam cracker complex 230/250 is routed to the py-gashydrotreatment and recovery center 600/620; C6-C9 aromatics stream 622are recovered for chemical markets, C5 raffinate 606 and non-aromatics646 (for instance, C6-C9) are recycled to the mixed feed steam crackingzone 230, and the heavy aromatics stream 642 (for instance, C10-C12products) is recovered. In certain embodiments ethylbenzene 628 can berecovered.

In the configuration depicted in FIG. 5, an optional diverter is shown,indicated as a diverter and stream in dashed lines, to bypass theprocess for conversion of a mixture of butenes into mixed butanols, totherefore divert all, a substantial portion, a significant portion or amajor portion of the C4 Raff-3 524 to the mixed feed steam cracking zone230. In a mixed butanol liquid mode of operation, flow can be directedto the mixed butanols production zone 550 for conversion of a mixture ofbutenes into mixed butanols. In further alternative modes, flow of theC4 Raff-3 524 can be directed to the mixed feed steam cracking zone 230and the mixed butanols production zone 550. In this manner, a producercan vary the quantity of feed to tailor the desired outputs.Accordingly, 0-100% of the third C4 raffinate stream 524 can be routedto mixed butanols production zone 550, and the remainder (if any) isdirected to the mixed feed steam cracking zone 230. The quantity can bedetermined, for instance, based upon demand for ethylene, demand formixed butanols, and/or minimum ranges for which the unit is operateddepending on design capacity.

FIG. 6 schematically depicts further embodiments of processes andsystems for conversion of crude oil to petrochemicals and fuel products.In this embodiment, additional step(s) of metathesis conversion of C4and C5 olefins to produce additional propylene, and/or conversion of amixture of butenes into mixed butanols suitable as a gasoline blendingoxygenate and for octane enhancement, are integrated. The processoperates as described with respect to FIG. 1 upstream of the steamcracking operations.

Downstream of the steam cracking operations, the butadiene extractiontrain can optionally operate in a manner similar to that in FIG. 3 shownas the stream 524 from a diverter (in dashed lines) from the C4distillation unit 520 directly to the mixed feed steam cracking zone 230as an optional mode of operation. The configuration in FIG. 6 integratesselective recovery of various alkene and diene pyrolysis chemicalshaving four carbons, metathesis conversion to produce additionalpropylene, and/or conversion of a mixture of butenes into mixed butanolssuitable as a gasoline blending oxygenate and for octane enhancement.

FIG. 6 depicts a stream 552 containing butenes from the C4 distillationstep (“C4 Raff-3”) that can be routed to a mixed butanols productionzone 550 for conversion of the mixture of butenes into mixed butanolliquids 554. Alkanes 556 are recycled to the mixed feed steam crackingzone 230. In addition, a portion 532 of the 2-butene rich raffinate-3from the C4 distillation unit 520 is passed to a metathesis unit 530 formetathesis conversion to additional propylene 534. As indicated, aportion 536 of the ethylene product 202 can be routed to the metathesisunit 530. In additional embodiments, ethylene for the metathesis unit530 is supplied from outside the complex limits, instead of or inaddition to the portion 536 of the ethylene product 202. A stream 538,having a mixture of mostly saturated C4/C5 from metathesis unit, isrecycled to the mixed feed steam cracking zone 230.

As in FIG. 3, in the configuration of FIG. 6, pyrolysis gasoline 212from the steam cracker complex 230/250 is routed to the py-gashydrotreatment and recovery center 600/620; C6-C9 aromatics stream 622,BTX, are recovered for chemical markets, non-aromatics 646 (forinstance, C6-C9) is recycled to the mixed feed steam cracking zone 230,and the heavy aromatics stream 642 (for instance, C10-C12 products) isrecovered. In certain embodiments ethylbenzene 628 can be recovered. Theraffinate stream 540 can be routed to the metathesis unit 530, as shown,and/or optionally recycled to the mixed feed steam cracking zone 230 asshown in dashed lines, stream 606. In certain embodiments (not shown),all or a portion of the cracked Cys from the py-gas hydrotreater can berouted to the metathesis unit 530 prior to aromatics extraction.

In the configuration depicted in FIG. 6, an optional diverter is shown,indicated as a diverter and stream in dashed lines, to bypass themetathesis conversion process and the process for conversion of amixture of butenes into mixed butanols, to therefore divert all, asubstantial portion, a significant portion or a major portion of the C4Raff-3 524 to the mixed feed steam cracking zone 230. An optional valvealso can be provided to direct flow of the C4 Raff-3 to one or both ofthe metathesis conversion unit 530 and/or the mixed butanols productionzone 550 for conversion of a mixture of butenes into mixed butanols. Infurther alternative modes, flow of the C4 Raff-3 524 can be directed toeach of the mixed feed steam cracking zone 230, the metathesisconversion unit 530 (as stream 532), and the mixed butanols productionzone 550 (as stream 552). In this manner, a producer can vary thequantity of feed to tailor the desired outputs. Accordingly, all, asubstantial portion, a significant portion or a major portion of thethird C4 raffinate stream can be routed to the metathesis conversionunit 530, and the remainder (if any) is directed to the mixed feed steamcracking zone 230 and/or the mixed butanols production zone 550. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the third C4 raffinate stream is routed to themetathesis conversion unit 530, and the remainder (if any) is directedto the mixed feed steam cracking zone 230. In further embodiments, all,a substantial portion, a significant portion or a major portion of thethird C4 raffinate stream is routed to the metathesis conversion unit530, and the remainder (if any) is directed to the mixed butanolsproduction zone 550 for production of mixed butanols. In furtherembodiments, all, a substantial portion, a significant portion or amajor portion of the third C4 raffinate stream is routed to the mixedbutanols production zone 550 for production of mixed butanols, and theremainder (if any) is directed to both the mixed feed steam crackingzone 230 and the metathesis conversion unit 530. In further embodiments,all, a substantial portion, a significant portion or a major portion ofthe third C4 raffinate stream is routed to the mixed butanols productionzone 550 for production of mixed butanols, and the remainder (if any) isdirected to the mixed feed steam cracking zone 230. In furtherembodiments, all, a substantial portion, a significant portion or amajor portion of the third C4 raffinate stream is routed to the mixedbutanols production zone 550 for production of mixed butanols, and theremainder (if any) is directed to the metathesis conversion unit 530.The quantity can be determined, for instance, based upon demand forethylene, demand for propylene, demand for mixed butanols, and/orminimum ranges for which the unit is operated depending on designcapacity.

FIGS. 7, 8 and 13 schematically depict embodiments of processes andsystems for conversion of crude oil to petrochemicals and fuel productsincluding a mixed feed steam cracking zone 230 and a gas oil steamcracking zone 250.

A crude oil feed 102 is passed to a crude complex 100, which generallyincludes an atmospheric distillation zone 110, a saturated gas plant 150and a vacuum distillation zone 160. The atmospheric distillation unitand vacuum distillation unit are used in well-known arrangements.

Intermediate streams obtained from the feed 102 via separation in thecrude complex 100 include: Off-gas 154, obtained within the crudecomplex 100 via the saturated gas plant 150, and the sweet off-gas canbe sent to the fuel gas system or to the steam cracker complex; a lightends stream 152, obtained within the crude complex 100 via the saturatedgas plant 150, and which is passed to the mixed feed steam cracking zone230; one or more straight run naphtha stream(s), in this embodiment alight naphtha stream 138 and a heavy naphtha stream 140, which arepassed to the mixed feed steam cracking zone 230; a first middledistillate stream 116 that is passed to a kerosene sweetening zone 170,such as a mercaptan oxidation zone; a second middle distillate stream122 that is passed to a diesel hydrotreating zone 180; a third middledistillate stream 126 that can be passed to the gas oil hydroprocessingzone, the gas oil steam cracking zone 250, or both the gas oilhydroprocessing zone and the gas oil steam cracking zone 250; anatmospheric residue fraction 114 that is passed to the vacuumdistillation zone 160; a light vacuum gas oil stream 164 and a heavyvacuum gas oil stream 166 from the vacuum distillation zone 160 that arepassed to the vacuum gas oil hydroprocessing zone; and a vacuum residuestream 168 from the vacuum distillation zone 160, all or a portion ofwhich is passed to a delayed coking zone 900. In certain embodiments thethird middle distillate stream 126 is routed to both the gas oilhydroprocessing zone and the gas oil steam cracking zone 250. Forinstance, the third middle distillate stream 126 can be two separatetemperature fractions of an atmospheric gas oil stream from the crudecomplex 100, including heavy AGO that is passed to the gas oilhydroprocessing zone, and medium AGO (if not contained in the secondmiddle distillate fraction 122) bypassing the gas oil hydroprocessingzone and routed to the gas oil steam cracking zone 250 withouthydrotreating In another arrangement, the third middle distillate stream126 can be divided based on volume or mass flow, for instance, with adiverter.

The intermediate streams from the crude complex 100 are used in anefficient manner in the integrated process and system herein. The lightends stream 152, and the straight run naphtha stream(s), in thisembodiment light naphtha 138 and heavy naphtha 140, are routed to themixed feed steam cracking zone 230 as feed for conversion into lightolefins and other valuable petrochemicals. Either or both of thestraight run naphtha streams, light naphtha 138 and heavy naphtha 140,can optionally be steam-stripped in a side stripper prior to routing tothe mixed feed steam cracking zone 230.

Components of the crude complex not shown but which are well-known caninclude feed/product and pump-around heat exchangers, crude chargeheaters, crude tower(s), product strippers, cooling systems, hot andcold overhead drum systems including re-contactors and off-gascompressors, and units for water washing of overhead condensing systems.The atmospheric distillation zone 110 can include well-known designfeatures. Furthermore, in certain embodiments, all or portions of thenaphtha, kerosene and atmospheric gas oil products from the atmosphericdistillation column are steam-stripped in side strippers, andatmospheric residue is steam-stripped in a reduced-size can sectioninside the bottom of the atmospheric distillation column.

The feed to the atmospheric distillation zone 110 is primarily the crudefeed 102, although it shall be appreciated that wild naphtha, LPGs andoff-gas streams from the diesel hydrotreating zone 180 and in certainembodiments from the vacuum gas oil hydroprocessing step and/or delayedcoking zone 900 can be routed to the atmospheric distillation zone 110where they are fractionated before being passed to the cracking complex.A desalting unit (not shown) is typically included upstream of thedistillation zone 110. A substantial amount of the water required fordesalting can be obtained from a sour water stripper within theintegrated process and system.

The desalting unit refers to a well-known arrangement of vessels fordesalting of crude oil, and as used herein is operated to reduce thesalt content to a target level, for instance, to a level of less than orequal to about 10, 5, or 3 wppm. In certain embodiments two or moredesalters are included to achieve a target salt content of less than orequal to about 3 wppm.

In one embodiment of a crude complex 100 herein, feed 102 is preheatedbefore entering a desalting unit, for instance, to a temperature (° C.)in the range of about 105-165, 105-150, 105-145, 120-165, 120-150,120-145, 125-165, 125-150, 125-145, and in certain embodiments about135. Suitable desalters are designed to remove salt down to a typicallevel of about 0.00285 kg/m³ (1 lb/1000 bbl) in a single stage. Incertain embodiments, plural preheat and desalting trains are employed.The desalter operating pressure can be based on a pressure margin abovecrude and water mixture vapor pressure at desalter operating temperatureto ensure liquid phase operation, for instance in the range of about2.75-4.15, 2.75-3.80, 2.75-3.65, 3.10-4.15, 3.10-3.80, 3.10-3.65,3.25-4.15, 3.25-3.80, 3.25-3.65 and in certain embodiments about 3.45barg.

The atmospheric distillation zone 110 can employ fractionated productsand pumparounds to provide enough heat for desalting. In certainembodiments, the desalter operating temperature can be controlled by adiesel pumparound swing heat exchanger. In certain embodiments, desalterbrine preheats desalter make-up water in a spiral type heat exchanger tominimize fouling and achieve rundown cooling against cooling waterbefore the brine is routed to the wastewater system.

In certain embodiments, desalted crude is preheated before entering apreflash tower, to a temperature (° C.) in the range of about 180-201,185-196, or 189-192. The preflash tower removes LPG and light naphthafrom the crude before it enters the final preheat exchangers. Thepreflash tower minimizes the operating pressure of the preheat train tomaintain liquid phase operation at the crude furnace pass valves andalso reduces the requisite size of the main crude column.

In one example of a suitable crude distillation system, a crude furnacevaporizes materials at or below a certain cut point, for instance, at atemperature (° C.) in the range of about 350-370, 355-365 or 360 (680°F.), before the crude enters the flash zone of the crude tower. Thefurnace is designed for a suitable outlet temperature, for instance, ata temperature (° C.) in the range of about 338-362, 344-354 or 348.9(660° F.). Crude column flash zone conditions are at a temperature (°C.) in the range about 328-374, 328-355, 337-374, 327-355, or 346.1(655° F.), and a pressure (barg) in the range of about 1.35-1.70,1.35-1.60, 1.44-1.70, 1.44-1.60 or 1.52.

In certain embodiments the crude tower contains 59 trays and producessix cuts, with draw temperatures for each product as follows: lightnaphtha, 104.4° C. (220° F.) (overhead vapor); heavy naphtha, 160.6° C.(321° F.) (sidedraw); kerosene, 205° C. (401° F.) (sidedraw); diesel,261.7° C. (503° F.) (sidedraw); AGO, 322.2° C. (612° F.) (sidedraw);atmospheric residue, 340.6° C. (645° F.) (bottoms). The heavy naphthadraw includes a reboiled side stripper against diesel pumparound, and iscontrolled to a 185° C. (365° F.) D86 end point. The kerosene drawincludes a steam stripper at 14.54 kg/m³ (5.1 lb steam per bbl); thedraw rate is limited on the back end by freeze point. The diesel drawincludes a steam stripper at 14.54 kg/m³ (5.1 lb steam per bbl), andthis draw is controlled to a 360° C. (680° F.) D86 95% point. The AGOdraw includes a steam stripper at 14.82 kg/m³ (5.2 lb steam per bbl),which sets the overflash at 2 vol % on crude. The crude tower alsocontains 3 pumparounds for top, diesel, and AGO. Diesel pumparoundprovides heat to the heavy naphtha stripper reboiler and debutanizerreboiler along with controlling desalter operating temperature via swingheat. The bottoms stream of the atmospheric column is steam stripped at28.5 kg/m³ (10 lb steam/bbl).

The atmospheric residue fraction 114 from the atmospheric distillationzone 110 is further distilled in the vacuum distillation zone 160, whichfractionates the atmospheric residue fraction 114 into a light vacuumgas oil stream 164 and a heavy vacuum gas oil streams 166 which are fedto the gas oil hydroprocessing zone, and a vacuum residue stream 168,all or a portion of which is routed to a delayed coking zone 900; anyportion not subjected to processing in the delayed coking zone 900 canbe routed, for instance, to a fuel oil pool (such as a high sulfur fueloil pool). The vacuum distillation zone 160 can include well-knowndesign features, such as operation at reduced pressure levels (mm Hgabsolute pressure), for instance, in the range of about 30-40, 32-36 or34, which can be maintained by steam ejectors or mechanical vacuumpumps. Vacuum bottoms can be quenched to minimize coking, for instance,via exchange against crude at a temperature (° C.) in the range of about334-352, 334-371, 338-352, 338-371 or 343.3 (650° F.). Vacuumdistillation can be accomplished in a single stage or in plural stages.In certain embodiments, the atmospheric residue fraction 114 is heatedin a direct fired furnace and charged to vacuum fractionator at atemperature (° C.) in the range of about 390-436, 390-446, 380-436,380-446 or 400-425.

In one embodiment, the atmospheric residue is heated to a temperature (°C.) in the range of about 399-420, 399-430, 389-420, 389-430 or 409.4(769° F.) in the vacuum furnace to achieve flash zone conditions of atemperature (° C.) in the range of about 392-412, 392-422, 382-412,382-422 or 401.7 (755° F.) and pressure levels (mm Hg absolute pressure)in the range of about 30-40, 32-36 or 34. The vacuum column is designedfor a theoretical cut point temperature (° C.) in the range of about524-551, 524-565, 511-551, 511-565 or 537.8 (1000° F.), by removinglight VGO and heavy VGO from the vacuum residue. The overhead vacuumsystem can include two parallel trains of jet ejectors each includingthree jets. A common vacuum pump is used at the final stage. In oneembodiment, the vacuum tower is sized for a 0.35 C-Factor and about a14.68 lpm/m² (0.3 gpm/ft²) wetting rate at the bottom of the wash zone.Wash zone slop wax is recycled to the vacuum furnace to minimize fueloil production. Vacuum bottoms are quenched via exchange against crudeto minimize coking at a temperature (° C.) in the range of about334-352, 334-371, 338-352, 338-371 or 343.3° C. (650° F.).

The saturated gas plant 150 generally comprises a series of operationsincluding fractionation and in certain systems absorption andfractionation, as is well known, with an objective to process light endsto separate fuel gas range components from LPG range components suitableas a steam cracker feedstock. The light ends that are processed in oneor more saturated gas plants within embodiments of the integrated systemand process herein are derived from the crude distillation, such aslight ends and LPG. In addition, other light products can optionally berouted to the saturated gas plant 150, shown in dashed lines as stream156, such as light gases from refinery units within the integratedsystem, and in certain embodiments light gases from outside of thebattery limits. For instance, stream 156 can contain off-gases and lightends from the diesel hydrotreating zone 180, the gas oil hydroprocessingzone, the py-gas hydrotreating zone 600 and/or the delayed coking zone900. The products from the saturated gas plant 150 include: an off-gasstream 154, containing C1-C2 alkanes, that is passed to the fuel gassystem and/or the cracker complex; and a light ends stream 152,containing C2+, that is passed to the mixed feed steam cracking unit230.

In certain embodiments, a suitable saturated gas plant 150 includesamine and caustic washing of liquid feed, and amine treatment of vaporfeed, before subsequent steps. The crude tower overhead vapor iscompressed and recontacted with naphtha before entering an aminescrubber for H₂S removal and is then routed to the steam crackercomplex. Recontact naphtha is debutanized to remove LPGs which are aminewashed and routed to the steam cracker complex. The debutanized naphthais routed separately from the heavy naphtha to the steam crackercomplex. As is known, light naphtha absorbs C4 and heavier hydrocarbonsfrom the vapor as it travels upward through an absorber/debutanizer.Off-gas from the absorber/debutanizer is compressed and sent to arefinery fuel gas system. A debutanizer bottoms stream is sent to themixed feed steam cracker as an additional source of feed.

As shown, the first middle distillate fraction 116 is processed in akerosene sweetening zone 170 to remove unwanted sulfur compounds, as iswell-known. Treated kerosene is recovered as a kerosene fuel product172, for instance, jet fuel compliant with Jet A or Jet A-1specifications, and optionally other fuel products. In certainembodiments herein, all or a portion of the first middle distillatefraction 116 is not used for fuel production, but rather is used as afeed for distillate hydroprocessing so as to produce additional feed forthe mixed feed steam cracking zone 230.

For instance, a suitable kerosene sweetening zone 170 can include, butis not limited to, systems based on Merox™ technology (Honeywell UOP,US), Sweetn'K technology (Axens, IFP Group Technologies, FR) or Thiolex™technology (Merichem Company, US). Processes of these types arewell-established commercially and appropriate operating conditions arewell known to produce kerosene fuel product 172 and disulfide oils asby-products. In certain kerosene sweetening technologies impregnatedcarbon is utilized as catalyst to promote conversion to disulfide oil.In certain embodiments, common treatment of sour water from the kerosenesweetening zone 170 and other unit operations is employed to maximizeprocess integration.

For example, one arrangement of a kerosene sweetening zone includescaustic wash of the kerosene feed for residual H₂S removal, employing anelectrostatic coalescer (for instance using 10 degrees Baumé). Thereactor vessel containing an effective quantity of activated carboncatalyst utilizes air in conjunction with the caustic solution to affectthe oxidation of mercaptan to disulfides. Caustic is separated fromtreated kerosene in the bottom section of the reactor. After waterwashing, kerosene product passes upwards through one of two parallelsalt filters to remove free water and some soluble water. The keroseneproduct passes downward through one of two parallel clay filters forremoval of solids, moisture, emulsions and surfactants, so as to ensurethat the kerosene product meets haze, color stability and waterseparation specifications, for instance, compliant with Jet Aspecifications.

The second middle distillate fraction 122 is processed in a dieselhydrotreating zone 180 in the presence of an effective amount ofhydrogen obtained from recycle within the diesel hydrotreating zone 180and make-up hydrogen 186. In certain embodiments, all or a portion ofthe make-up hydrogen 186 is derived from the steam cracker hydrogenstream 210 from the olefins recovery train 270. A suitable hydrotreatingzone 180 can include, but is not limited to, systems based on technologycommercially available from Honeywell UOP, US; Chevron Lummus Global LLC(CLG), US; Axens, IFP Group Technologies, FR; Haldor Topsoe A/S, DK; orjoint technology from KBR, Inc, US, and Shell Global Solutions, US.

The diesel hydrotreating zone 180 operates under conditions effectivefor removal of a significant amount of the sulfur and other knowncontaminants, for instance, to meet necessary sulfur specifications forthe diesel fuel fraction 182, such as diesel fuel compliant with Euro Vdiesel standards. In addition, a hydrotreated naphtha fraction 184(sometimes referred to as wild naphtha) is recovered from the dieselhydrotreating zone 180, which is routed to the mixed feed steam crackingzone 230 as one of plural steam cracking feed sources. Effluentoff-gases are recovered from the diesel hydrotreating zone 180 and arepassed to the olefins recovery train, the saturated gas plant as part ofthe other gases stream 156, and/or directly to a fuel gas system.Liquefied petroleum gas can be recovered from the diesel hydrotreatingzone 180 and routed to the mixed feed steam cracking zone, the olefinsrecovery train and/or the saturated gas plant. In certain embodiments,the hydrotreated naphtha fraction 184 is routed through the crudecomplex 100, alone, or in combination with other wild naphtha fractionsfrom within the integrated process. In embodiments in which hydrotreatednaphtha fraction 184 is routed through the crude complex 100, all or aportion of the liquefied petroleum gas produced in the dieselhydrotreating zone 180 can be passed with the hydrotreated naphthafraction 184. In certain embodiments, all, a substantial portion or asignificant portion of the wild naphtha 184 is routed to the mixed feedsteam cracking zone 230 (directly or through the crude complex 100).

The diesel hydrotreating zone 180 can optionally process other fractionsfrom within the complex (not shown). In embodiments in which a kerosenesweetening zone 170 is used, all or a portion of the disulfide oil canbe additional feed to the diesel hydrotreating zone 180. Further, all ora portion of the first middle distillate fraction 116 can be additionalfeed to the diesel hydrotreating zone 180. Additionally, all or aportion of the first middle distillate fraction 116, and/or all or aportion of distillates from the vacuum gas oil hydroprocessing zone, canbe routed to the diesel hydrotreating zone 180. Any portion ofdistillates not routed to the diesel hydrotreating zone 180 can bepassed to the crude complex 100 or routed to the mixed feed steamcracking zone 230.

The diesel hydrotreating zone 180 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement. In certainembodiments, the diesel hydrotreating zone 180 contains a layered bedreactor with three catalyst beds and having inter-bed quench gas, andemploys a layered catalyst system with the layer of hydrodewaxingcatalyst positioned between beds of hydrotreating catalyst. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the dieselhydrotreating zone 180. In addition, equipment including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the diesel hydrotreating zone 180, arewell known and are considered part of the diesel hydrotreating zone 180.

In certain embodiments, the diesel hydrotreating zone 180 operatingconditions include:

a reactor inlet temperature (° C.) in the range of from about 296-453,296-414, 296-395, 336-453, 336-414, 336-395, 355-453, 355-414, 355-395or 370-380;

a reactor outlet temperature (° C.) in the range of from about 319-487,319-445, 319-424, 361-487, 361-445, 361-424, 382-487, 382-445, 382-424or 400-406;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 271-416, 271-379,271-361, 307-416, 307-379, 307-361, 325-416, 325-379, 325-361 or340-346;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 311-476, 311-434, 311-414, 352-476, 352-434, 352-414,373-476, 373-434, 373-414 or 390-396;

a reaction inlet pressure (barg) in the range of from about 48-72,48-66, 48-63, 54-72, 54-66, 54-63, 57-72, 57-66 or 57-63;

a reaction outlet pressure (barg) in the range of from about 44-66,44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60 or 52-58;

a hydrogen partial pressure (barg) (outlet) in the range of from about32-48, 32-44, 32-42, 36-48, 36-44, 36-42, 38-48, 38-44 or 38-42;

a hydrogen treat gas feed rate (standard liters per liter of hydrocarbonfeed, SLt/Lt) up to about 400, 385, 353 or 337, in certain embodimentsfrom about 256-385, 256-353, 256-337, 289-385, 289-353, 289-337,305-385, 305-353 or 305-337;

a hydrogen quench gas feed rate (SLt/Lt) up to about 100, 85, 78 or 75,in certain embodiments from about 57-85, 57-78, 57-75, 64-85, 64-78,64-75, 68-85, 68-78 or 68-75; and

a make-up hydrogen feed rate (SLt/Lt) up to about 110, 108, 100 or 95,in certain embodiments from about 70-108, 70-100, 70-95, 80-108, 80-100,80-95, 85-108, 85-100 or 85-95.

An effective quantity of hydrotreating catalyst is provided in thediesel hydrotreating zone 180, including those possessing hydrotreatingfunctionality and which generally contain one or more active metalcomponent of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 6-10. In certainembodiments, the active metal component is one or more of Co, Ni, W andMo. The active metal component is typically deposited or otherwiseincorporated on a support, such as amorphous alumina, amorphous silicaalumina, zeolites, or combinations thereof. The catalyst used in thediesel hydrotreating zone 180 can include one or more catalyst selectedfrom Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo. Combinations of one or more ofCo/Mo, Ni/Mo, Ni/W and Co/Ni/Mo, can also be used. The combinations canbe composed of different particles containing a single active metalspecies, or particles containing multiple active species. In certainembodiments, Co/Mo hydrodesulfurization catalyst is suitable. Effectiveliquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrotreating catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5-10.0,0.5-5.0, 0.5-2.0 or 0.8-1.2. Suitable hydrotreating catalysts used inthe diesel hydrotreating zone 180 have an expected lifetime in the rangeof about 28-44, 34-44, 28-38 or 34-38 months.

In certain embodiments, an effective quantity of hydrodewaxing catalystis also added. In such embodiments, effective hydrodewaxing catalystsinclude those typically used for isomerizing and cracking paraffinichydrocarbon feeds to improve cold flow properties, such as catalystscomprising Ni, W, or molecular sieves or combinations thereof. Catalystcomprising Ni/W, zeolite with medium or large pore sizes, or acombination thereof are suitable, along with catalyst comprisingaluminosilicate molecular sieves such as zeolites with medium or largepore sizes. Effective commercial zeolites include for instance ZSM-5,ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM 35, and zeolites of type beta and Y.Hydrodewaxing catalyst is typically supported on an oxide support suchas Al₂O₃, SiO₂, ZrO₂, zeolites, zeolite-alumina, alumina-silica,alumina-silica-zeolite, activated carbon, and mixtures thereof.Effective liquid hourly space velocity values (h⁻¹), on a fresh feedbasis relative to the hydrodewaxing catalyst, are in the range of fromabout 0.1-12.0, 0.1-8.0, 0.1-4.0, 0.5-12.0, 0.5-8.0, 0.5-4.0, 1.0-12.0,1.0-8.0, 1.0-4.0 or 1.6-2.4. Suitable hydrodewaxing catalysts used inthe diesel hydrotreating zone 180 have an expected lifetime in the rangeof about 28-44, 34-44, 28-38 or 34-38 months.

In high capacity operations, two or more parallel trains of reactors areutilized. In such embodiments, the flow in the diesel hydrotreating zone180 is split after the feed pump into parallel trains, wherein eachtrain contains feed/effluent heat exchangers, feed heater, a reactor andthe hot separator. Each reactor contains three catalyst beds withinter-bed quench gas. A layered catalyst system is used with the layerof hydrodewaxing catalyst positioned between beds of hydrotreatingcatalyst. The trains recombine after the hot separators. Tops from thehot separators are combined and passed to a cold separator. Bottoms fromthe hot separators and from the cold separator are passed to a productstripper to produce stabilized ultra-low sulfur diesel and wild naphtha.Tops from the cold separator are subjected to absorption and aminescrubbing. Recycle hydrogen is recovered, and passed (along with make-uphydrogen) to the reaction zone as treat gas and quench gas.

The light vacuum gas oil stream 164 and heavy vacuum gas oil stream 166(or full range VGO, not shown) are processed in a gas oilhydroprocessing zone, in the presence of an effective amount of hydrogenobtained from recycle within the gas oil hydroprocessing zone andmake-up hydrogen 302. In certain embodiments, all, a substantialportion, a significant portion or a major portion of the coker gas oilstream 904 is also processed in the gas oil hydroprocessing zone. Incertain embodiments, all or a portion of the make-up hydrogen 302 isderived from the steam cracker hydrogen stream 210 from the olefinsrecovery train 270. In certain embodiments (not shown in FIGS. 7 and 8),all or a portion of the heavy middle distillate fraction, such as aportion of the third middle distillate fraction 126, e.g., atmosphericgas oil from the atmospheric distillation zone 110, can also be treatedin the gas oil hydroprocessing zone. The heavy middle distillatefraction can include a full range atmospheric gas oil, or a fractionthereof such as heavy atmospheric gas oil. Further, a portion of thethird middle distillate fraction 126 can be routed to the gas oilhydroprocessing zone, while the remainder bypasses gas oilhydroprocessing zone and is routed to the gas oil steam cracking zone250 without passing through the gas oil hydroprocessing zone. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the combined vacuum gas oil, streams 164 and 166, isrouted to the vacuum gas oil hydroprocessing zone; the remainder ofvacuum gas oil (if any) can be routed directly to the gas oil steamcracking zone 250, bypassing the vacuum gas oil hydroprocessing zone.

In accordance with the process herein, the severity of the gas oilhydroprocessing operation can be used to moderate the relative yield ofolefin and aromatic chemicals from the overall complex and improve theeconomic threshold of cracking heavy feeds. This application of a gasoil hydroprocessing zone. as a chemical yield control mechanism, isuncommon in the industry, where fuels products are typically the productobjectives.

FIG. 7 depicts a hydrocracking mode of operation for treatment of thevacuum gas oil. Hydrocracking processes are used commercially in a largenumber of petroleum refineries. They are used to process a variety offeeds boiling above the atmospheric gas oil range (for example, in therange of about 370 to 520° C.) in conventional hydrocracking units andboiling above the vacuum gas oil range (for example, above about 520°C.) in residue hydrocracking units. In general, hydrocracking processessplit the molecules of the feed into smaller, i.e., lighter, moleculeshaving higher average volatility and economic value. Additionally,hydrocracking processes typically improve the quality of the hydrocarbonfeedstock by increasing the hydrogen-to-carbon ratio and by removingorganosulfur and organonitrogen compounds. The significant economicbenefit derived from hydrocracking processes has resulted in substantialdevelopment of process improvements and more active catalysts.

Three major hydrocracking process schemes include single-stage oncethrough hydrocracking, series-flow hydrocracking with or withoutrecycle, and two-stage recycle hydrocracking. Single-stage once throughhydrocracking is the simplest of the hydrocracker configuration andtypically occurs at operating conditions that are more severe thanhydrotreating processes, and less severe than conventional higherpressure hydrocracking processes. It uses one or more reactors for bothtreating steps and cracking reaction, so the catalyst must be capable ofboth hydrotreating and hydrocracking. This configuration is costeffective, but typically results in relatively low product yields (forexample, a maximum conversion rate of about 50 wt %). Single stagehydrocracking is often designed to maximize mid-distillate yield over asingle or dual catalyst systems. Dual catalyst systems can be used in astacked-bed configuration or in two different reactors. The effluentsare passed to a fractionator column to separate the H₂S, NH₃, lightgases (C1-C4), naphtha and diesel products, boiling in the temperaturerange including and below atmospheric gas oil range fractions (forinstance in the temperature range of 36-370° C.). The hydrocarbonsboiling above the atmospheric gas oil range (for instance 370° C.) aretypically unconverted oils. Any portion of these unconverted oils thatare not recycled are drawn from a bottoms fraction in a gas oilhydrocracking zone 320 as a hydrogen-rich bleed stream and iseffectively integrated as feed to the gas oil steam cracking zone 250 asdescribed herein. In certain embodiments, unconverted oils can beprocessed in a lube oil production unit (not shown).

The gas oil hydrocracking zone 320 operates under mild, moderate orsevere hydrocracking conditions, and generally produces off-gas andlight ends (not shown), a wild naphtha stream 326, a diesel fuelfraction 322, and an unconverted oil fraction 324. Effluent off-gasesare recovered from the gas oil hydrocracking zone 320 and are passed tothe olefins recovery train, the saturated gas plant as part of the othergases stream 156, and/or directly to a fuel gas system. Liquefiedpetroleum gas can be recovered from the gas oil hydrocracking zone 320and routed to the mixed feed steam cracking zone, the olefins recoverytrain and/or the saturated gas plant. The naphtha fraction 326 is routedto the mixed feed steam cracking zone 230. In certain embodiments, thenaphtha fraction 326 is routed through the crude complex 100, alone, orin combination with other wild naphtha fractions from within theintegrated process. In embodiments in which naphtha fraction 326 isrouted through the crude complex 100, all or a portion of the liquefiedpetroleum gas produced in the gas oil hydrocracking zone 320 can bepassed with the naphtha fraction 326. The unconverted oil fraction 324is routed to the gas oil steam cracking zone 250. The diesel fuelfraction 322 is recovered as fuel, for instance, compliant with Euro Vdiesel standards, and can be combined with the diesel fuel fraction 182from the diesel hydrotreating zone 180.

Vacuum gas oil hydrocracking zone 320 can operate under mild, moderateor severe conditions, depending on factors including the feedstock andthe desired degree of conversion. Such conditions are effective forremoval of a significant amount of the sulfur and other knowncontaminants, and for conversion of the feed(s) into a major proportionof hydrocracked products and minor proportions of off-gases, light endsand unconverted product that is passed to the gas oil steam crackingzone 250.

For instance, a suitable vacuum gas oil hydrocracker zone 320 caninclude, but is not limited to, systems based on technology commerciallyavailable from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US;Axens, IFP Group Technologies, FR; or Shell Global Solutions, US.

The gas oil hydrocracking zone 320 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the gas oilhydrocracking zone 320. In addition, equipment, including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the gas oil hydrocracking zone 320, arewell known and are considered part of the gas oil hydrocracking zone320.

Series-flow hydrocracking with or without recycle is one of the mostcommonly used configuration. It uses one reactor (containing bothtreating and cracking catalysts) or two or more reactors for bothtreating and cracking reaction steps. In a series-flow configuration theentire hydrocracked product stream from the first reaction zone,including light gases (typically C₁-C₄, H₂S, NH₃) and all remaininghydrocarbons, are sent to the second reaction zone. Unconverted bottomsfrom the fractionator column are recycled back into the first reactorfor further cracking. This configuration converts heavy crude oilfractions such as vacuum gas oil, into light products and has thepotential to maximize the yield of naphtha, kerosene and or diesel rangehydrocarbons, depending on the recycle cut point used in thedistillation section.

Two-stage recycle hydrocracking uses two reactors and unconvertedbottoms from the fractionation column are passed to the second reactorfor further cracking. Since the first reactor accomplishes bothhydrotreating and hydrocracking, the feed to second reactor is virtuallyfree of ammonia and hydrogen sulfide. This permits the use of highperformance zeolite catalysts which are susceptible to poisoning bysulfur or nitrogen compounds.

Effective hydrocracking catalyst generally contain about 5-40 wt % basedon the weight of the catalyst, of one or more active metal component ofmetals or metal compounds (oxides or sulfides) selected from thePeriodic Table of the Elements IUPAC Groups 6-10. In certainembodiments, the active metal component is one or more of Mo, W, Co orNi. The active metal component is typically deposited or otherwiseincorporated on a support, such as amorphous alumina, amorphous silicaalumina, zeolites, or combinations thereof. In certain embodiments,alone or in combination with the above metals, Pt group metals such asPt and/or Pd, may be present as a hydrogenation component, generally inan amount of about 0.1-2 wt % based on the weight of the catalyst.Suitable hydrocracking catalyst have an expected lifetime in the rangeof about 18-30, 22-30, 18-26 or 22-26 months.

Exemplary products from the gas oil hydrocracking zone 320 include27-99, 27-90, 27-82, 27-80, 27-75, 27-52, 27-48, 30-99, 30-90, 30-82,30-80, 30-75, 30-52, 30-48, 48-99, 48-90, 48-82, 48-80, 48-75, 48-52,78-99, 78-90, 78-85, 80-90 or 80-99 wt % of effluent (relative to thefeed to the gas oil hydrocracking zone 320) boiling at or below theatmospheric residue end boiling point, such as 370° C., including LPG,kerosene, naphtha, and atmospheric gas oil range components. Theremaining bottoms fraction is the unconverted oil fraction, all or aportion of which can be effectively integrated as feed to the gas oilsteam cracking zone 250 as described herein.

FIG. 9 schematically depicts embodiments of a once-through singlereactor hydrocracking zone 330 including a reaction zone 332 and afractionating zone 342, which can as a mild conversion or partialconversion hydrocracker.

Reaction zone 332 generally includes one or more inlets in fluidcommunication with a source of initial feedstock 334 and a source ofhydrogen gas 338. One or more outlets of reaction zone 332 thatdischarge effluent stream 340 is in fluid communication with one or moreinlets of the fractionating zone 342 (typically including one or morehigh pressure and/or low pressure separation stages therebetween forrecovery of recycle hydrogen, not shown).

Fractionating zone 342 includes one or more outlets for discharginggases 344, typically H₂, H₂S, NH₃, and light hydrocarbons (C1-C4); oneor more outlets for recovering product 346, such as middle distillatesnaphtha and diesel products boiling in the temperature range includingand below atmospheric gas oil range fractions (for instance in thetemperature range of 36-370° C.); and one or more outlets fordischarging bottoms 348 including hydrocarbons boiling above theatmospheric gas oil range (for instance 370° C.). In certainembodiments, the temperature cut point for bottoms 348 (andcorrespondingly the end point for the products 346) is a rangecorresponding to the upper temperature limit of the desired gasoline,kerosene and/or diesel product boiling point ranges for downstreamoperations.

In operation of the once-through single reactor hydrocracking zone 330,a feedstock stream 334 and a hydrogen stream 338 are charged to thereaction zone 332. Hydrogen stream 338 is an effective quantity ofhydrogen to support the requisite degree of hydrocracking, feed type,and other factors, and can be any combination including, recyclehydrogen 336 from optional gas separation subsystems (not shown)associated with reaction zone 332, and/or derived from fractionator gasstream 344 and make-up hydrogen 302, if necessary. In certainembodiments, a reaction zone can contain multiple catalyst beds and canreceive one or more quench hydrogen streams between the beds (notshown).

The reaction effluent stream 340 contains converted, partially convertedand unconverted hydrocarbons. Reaction effluent stream 340 is passed tofractionating zone 342 (optionally after one or more high pressure andlow pressure separation stages to recover recycle hydrogen), generallyto recover gas and liquid products and by-products 344, 346, andseparate a bottoms fraction 348. This stream 348 is routed to the gasoil steam cracking zone 250 as described herein.

Gas stream 344, typically containing H₂, H₂S, NH₃, and lighthydrocarbons (C1-C4), is discharged and recovered and can be furtherprocessed. Effluent off-gases are passed to the olefins recovery train,the saturated gas plant as part of the other gases stream 156, and/ordirectly to a fuel gas system. Liquefied petroleum gas can be recoveredand routed to the mixed feed steam cracking zone, the olefins recoverytrain and/or the saturated gas plant. One or more cracked productstreams 346 are discharged via appropriate outlets of the fractionatorand can be further processed and/or blended in downstream refineryoperations to produce gasoline, kerosene and/or diesel fuel, or otherpetrochemical products.

In certain embodiments (not shown), fractionating zone 342 can operateas a flash vessel to separate heavy components at a suitable cut point,for example, a range corresponding to the upper temperature range of thedesired gasoline, kerosene and/or diesel products for downstreamoperations. In certain embodiments, a suitable cut point is in the rangeof 350 to 450° C., 360 to 450° C., 370 to 450° C., 350 to 400° C., 360to 400° C., 370 to 400° C., 350 to 380° C., or 360 to 380° C. The streamabove that cut point is routed to the gas oil steam cracking zone 250 asdescribed herein.

For instance, a suitable once-through single reactor hydrocracking zone330 can include, but is not limited to, systems based on technologycommercially available from Honeywell UOP, US; Chevron Lummus Global LLC(CLG), US; Axens, IFP Group Technologies, FR; or Shell Global Solutions,US.

The reactor arrangement in the once-through single reactor hydrocrackingzone 330 can contain one or more fixed-bed, ebullated-bed, slurry-bed,moving bed, continuous stirred tank (CSTR), or tubular reactors, whichcan be in parallel arrangement. The once-through single reactorhydrocracking zone 330 can operate in a mild hydrocracking mode ofoperation or a partial conversion mode of operation. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the once-throughsingle reactor hydrocracking zone 330. In addition, equipment, includingpumps, compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the once-through single reactorhydrocracking zone 330, are well known and are considered part of theonce-through single reactor hydrocracking zone 330.

In certain embodiments, operating conditions for the reactor(s) inhydrocracking zone 330 using a once-through (single stage withoutrecycle) configuration and operating in a mild hydrocracking modeinclude:

a reactor inlet temperature (° C.) in the range of from about 329-502,329-460, 329-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 338-516,338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 108-161,108-148, 108-141, 121-161, 121-148, 121-141, 128-161, 128-148, 128-141or 131-137;

a reaction outlet pressure (barg) in the range of from about 100-150,100-137, 100-130, 112-150, 112-137, 112-130, 118-150, 118-137 or118-130;

a hydrogen partial pressure (barg) (outlet) in the range of from about77-116, 77-106, 77-101, 87-116, 87-106, 87-101, 92-116, 92-106, 92-101or 94-98;

a hydrogen treat gas feed rate (SLt/Lt) up to about 530, 510, 470 or450, in certain embodiments from about 340-510, 340-470, 340-450,382-510, 382-470, 382-450, 400-510, 400-470, 400-450 or 410-440;

a hydrogen quench gas feed rate (SLt/Lt) up to about 470, 427, 391 or356, in certain embodiments from about 178-427, 178-214, 178-356,214-321 or 178-391;

make-up hydrogen rate (SLt/Lt) up to about 225, 215, 200 or 190, incertain embodiments from about 143-215, 143-200, 143-190, 161-215,161-200, 161-190, 170-215, 170-200 or 170-190; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0,0.4-5.0 or 0.5-3.0.

Under the above conditions and catalyst selections, exemplary productsfrom the once-through single reactor hydrocracking zone 330 operating ina mild hydrocracking mode of operation include 27-52, 27-48, 30-50 or30-52 wt % of effluent (relative to the feed to the gas oilhydrotreating zone 330) boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe unconverted oil fraction, all or a portion of which can beeffectively integrated as feed to the gas oil steam cracking zone 250 asdescribed herein.

In certain embodiments, operating conditions for the reactor(s) inhydrocracking zone 330 using a once-through (single stage withoutrecycle) configuration and operating in a partial conversion modeinclude:

a reactor inlet temperature (° C.) in the range of from about 340-502,340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 350-516,350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 100-165,100-150, 100-140, 120-165, 120-140, 130-165, 130-150, or 130-140;

a reaction outlet pressure (barg) in the range of from about 92-150,92-137, 92-130, 112-150, 112-127, 112-130, 118-140, 118-130;

a hydrogen partial pressure (barg) (outlet) in the range of from about80-120, 80-106, 80-101, 90-120, 90-106, 90-101, 100-120, or 100-115;

a hydrogen treat gas feed rate (SLt/Lt) up to about 677, 615, 587 or573, in certain embodiments from about 503-615, 503-587, 503-573,531-615, 531-587, 531-573, 545-615, 545-587, or 545-573;

a hydrogen quench gas feed rate (SLt/Lt) up to about 614, 558, 553 or520, in certain embodiments from about 457-558, 457-533, 457-520,482-558, 482-533, 482-520, 495-558, 495-533, or 495-520;

make-up hydrogen rate (SLt/Lt) up to about 305, 277, 264 or 252, incertain embodiments from about 204-277, 204-264, 204-252, 216-277,216-264, 216-252, 228-277, 228-264, or 228-252; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0,0.4-5.0, 0.4-2.0 or 0.5-3.0.

Under the above conditions and catalyst selections, exemplary productsfrom the once-through single reactor hydrocracking zone 330 operating asa partial conversion hydrocracker include 48-82, 50-80, 48-75, or 50-75wt % of effluent (relative to the feed to the gas oil hydrotreating zone330) boiling at or below the atmospheric residue end boiling point, suchas 370° C., including LPG, kerosene, naphtha, and atmospheric gas oilrange components. The remaining bottoms fraction is the unconverted oilfraction, all or a portion of which can be effectively integrated asfeed to the gas oil steam cracking zone 250 as described herein.

FIG. 10 schematically depicts another embodiment of a series flowhydrocracking zone 350, which operates as series-flow hydrocrackingsystem with recycle to the first reactor zone, the second reactor zone,or both the first and second reactor zones. In general, series flowhydrocracking zone 350 includes a first reaction zone 352, a secondreaction zone 358 and a fractionating zone 342.

First reaction zone 352 generally includes one or more inlets in fluidcommunication with a source of initial feedstock 334, a source ofhydrogen gas 338, and in certain embodiments recycle stream 364 acomprising all or a portion of the fractionating zone 342 bottoms stream348 and optionally a portion of fractionating zone 342 product stream362. One or more outlets of the first reaction zone 352 that dischargeeffluent stream 354 is in fluid communication with one or more inlets ofthe second reaction zone 358. In certain embodiments, the effluents 354are passed to the second reaction zone 358 without separation of anyexcess hydrogen and light gases. In optional embodiments, one or morehigh pressure and low pressure separation stages are provided betweenthe first and second reaction zones 352, 358 for recovery of recyclehydrogen (not shown).

The second reaction zone 358 generally includes one or more inlets influid communication with one or more outlets of the first reaction zone352, optionally a source of additional hydrogen gas 356, and in certainembodiments a recycle stream 364 b comprising all or a portion of thefractionating zone 342 bottoms stream 348 and optionally a portion offractionating zone 342 product stream 362. One or more outlets of thesecond reaction zone 358 that discharge effluent stream 360 is in fluidcommunication with one or more inlets of the fractionating zone 342(optionally having one or more high pressure and low pressure separationstages in between the second reaction zone 358 and the fractionatingzone 342 for recovery of recycle hydrogen, not shown).

Fractionating zone 342 includes one or more outlets for discharginggases 344, typically H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄); oneor more outlets for recovering product 346, such as middle distillatesnaphtha and diesel products boiling in the temperature range includingand below atmospheric gas oil range fractions (for instance in thetemperature range of 36-370° C.); and one or more outlets fordischarging bottoms 348 including hydrocarbons boiling above theatmospheric gas oil range (for instance about 370° C.), from which ableed stream 368 is obtained in processes that do not operate with 100%recycle. In certain embodiments, the temperature cut point for bottoms348 (and correspondingly the end point for the products 346) is a rangecorresponding to the upper temperature limit of the desired gasoline,kerosene and/or diesel product boiling point ranges for downstreamoperations.

In operation of the series flow hydrocracking zone 350, a feedstockstream 334 and a hydrogen stream 338 are charged to the first reactionzone 352. Hydrogen stream 338 is an effective quantity of hydrogen tosupport the requisite degree of hydrocracking, feed type, and otherfactors, and can be any combination including, recycle hydrogen 336 fromoptional gas separation subsystems (not shown) associated with reactionzones 352 and 358, and/or derived from fractionator gas stream 344 andmake-up hydrogen 302. In certain embodiments, a reaction zone cancontain multiple catalyst beds and can receive one or more quenchhydrogen streams between the beds (not shown).

First reaction zone 352 operates under effective conditions forproduction of reaction effluent stream 354 which is passed to the secondreaction zone 358 (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen), optionallyalong with an additional hydrogen stream 356. Second reaction zone 358operates under conditions effective for production of the reactioneffluent stream 360, which contains converted, partially converted andunconverted hydrocarbons.

The reaction effluent stream 360 is passed to fractionating zone 342,generally to recover gas and liquid products and by-products 344, 346,and separate a bottoms fraction 348. A portion of the bottoms fraction348, stream 368 is routed to the gas oil steam cracking zone 250 asdescribed herein.

Gas stream 344, typically containing H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄), is discharged and recovered and can be furtherprocessed. Effluent off-gases are passed to the olefins recovery train,the saturated gas plant as part of the other gases stream 156, and/ordirectly to a fuel gas system. Liquefied petroleum gas can be recoveredand routed to the mixed feed steam cracking zone, the olefins recoverytrain and/or the saturated gas plant. One or more cracked productstreams 346 are discharged via appropriate outlets of the fractionatorand can be further processed and/or blended in downstream refineryoperations to produce gasoline, kerosene and/or diesel fuel, or otherpetrochemical products. In certain embodiments, a diesel fraction 362derived from the one or more cracked product streams 346 can beintegrated with the recycle streams to the reactors. This integrationadds to the flexibility of the configuration between production ofdiesel fuel or petrochemicals from the product streams 346.

In certain embodiments (not shown), fractionating zone 342 can operateas a flash vessel to separate heavy components at a suitable cut point,for example, a range corresponding to the upper temperature range of thedesired gasoline, kerosene and/or diesel products for downstreamoperations. In certain embodiments, a suitable cut point is in the rangeof 350 to 450° C., 360 to 450° C., 370 to 450° C., 350 to 400° C., 360to 400° C., 370 to 400° C., 350 to 380° C., or 360 to 380° C. The streamabove that cut point is routed to the gas oil steam cracking zone 250 asdescribed herein.

All or a portion of the fractionator bottoms stream 348 from thereaction effluent is recycled to the first or second reaction zones 352and/or 358 (streams 364 a and/or 364 b). In certain embodiments, aportion of the fractionator bottoms from the reaction effluent isremoved as bleed stream 368. Bleed stream 368 can be about 0-10 vol %,1-10 vol %, 1-5 vol % or 1-3 vol % of the fractionator bottoms 348. Thisstream 368 is routed to the gas oil steam cracking zone 250 as describedherein.

Accordingly, all or a portion of the fractionator bottoms stream 348 isrecycled to the second reaction zone 358 as stream 364 b, the firstreaction zone 352 as stream 364 a, or both the first and second reactionzones 352 and 358. For instance, stream 364 a recycled to zone 352comprises 0 to 100 vol %, in certain embodiments 0 to about 80 vol %,and in further embodiments 0 to about 50 vol % of stream 348, and stream364 b recycled to zone 358 comprises 0 to 100 vol %, in certainembodiments 0 to about 80 vol %, and in further embodiments 0 to about50 vol % of stream 348. In certain embodiments, in which the recycle isat or approaches 100 vol %, recycle of the unconverted oil increases theyield of products suitable as feed to the mixed feed steam cracking zone230.

For instance, a suitable series flow hydrocracking zone 350 can include,but is not limited to, systems based on technology commerciallyavailable from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US;Axens, IFP Group Technologies, FR; or Shell Global Solutions, US.

The reactor arrangement in the series flow hydrocracking zone 350 cancontain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed,continuous stirred tank (CSTR), or tubular reactors, which can be inparallel arrangement. Additional equipment, including exchangers,furnaces, feed pumps, quench pumps, and compressors to feed thereactor(s) and maintain proper operating conditions, are well known andare considered part of the series flow hydrocracking zone 350. Inaddition, equipment, including pumps, compressors, high temperatureseparation vessels, low temperature separation vessels and the like toseparate reaction products and provide hydrogen recycle within theseries flow hydrocracking zone 350, are well known and are consideredpart of the series flow hydrocracking zone 350.

In certain embodiments, operating conditions for the first reactor(s) inhydrocracking zone 350 using once-through series configuration operatingin a partial conversion mode of operation include:

a reactor inlet temperature (° C.) in the range of from about 340-502,340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 350-516,350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 100-165,100-150, 100-140, 120-165, 120-140, 130-165, 130-150, or 130-140;

a reaction outlet pressure (barg) in the range of from about 92-150,92-137, 92-130, 112-150, 112-127, 112-130, 118-140, 118-130;

a hydrogen partial pressure (barg) (outlet) in the range of from about80-120, 80-106, 80-101, 90-120, 90-106, 90-101, 100-120, or 100-115;

a hydrogen treat gas feed rate (SLt/Lt) up to about 668, 607, 580 or566, in certain embodiments from about 497-607, 497-580, 497-566,525-607, 525-580, 525-566, 538-607, 538-580, or 538-566;

a hydrogen quench gas feed rate (SLt/Lt) up to about 819, 744, 711 or694, in certain embodiments from about 609-744, 609-711, 609-694,643-744, 643-711, 643-694, 660-744, 660-711, or 660-694;

make-up hydrogen rate (SLt/Lt) up to about 271, 246, 235 or 224, incertain embodiments from about 182-246, 182-235, 182-224, 192-246,192-235, 192-224, 203-246, 203-235, or 203-224; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0,0.4-5.0, 0.4-2.0 or 0.5-1.5.

In certain embodiments, operating conditions for the second reactor(s)in hydrocracking zone 350 using once-through series configurationoperating in a partial conversion mode of operation include:

In certain embodiments, partial conversion hydrocracking usingonce-through configuration operating conditions include:

a reactor inlet temperature (° C.) in the range of from about 340-502,340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 350-516,350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 90-150,90-130, 90-140, 110-150, 110-130, 110-145, or 130-150;

a reaction outlet pressure (barg) in the range of from about 85-140,85-127, 100-140, 112-130, 112-140, or 118-130;

hydrogen partial pressure (barg) (outlet) in the range of from about80-130, 80-120, 80-101, 90-130, 90-120, 90-101, 100-130, or 100-115;

a hydrogen treat gas feed rate (SLt/Lt) up to about 890, 803, 767 or748, in certain embodiments from about 657-803, 657-767, 657-748,694-803, 694-767, 694-748, 712-803, 712-767, or 712-748;

a hydrogen quench gas feed rate (SLt/Lt) up to about 850, 764, 729 or712, in certain embodiments from about 625-764, 625-729, 625-712,660-764, 660-729, 660-712, 677-764, 677-729, or 677-712;

make-up hydrogen rate (SLt/Lt) up to about 372, 338, 323 or 309, incertain embodiments from about 250-338, 250-323, 250-309, 264-338,264-323, 264-309, 279-338, 279-323, or 279-309; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 1.0-5.0, 2.0-4.0 or1.0-3.0.

Under the above conditions and catalyst selections, exemplary productsfrom the series-flow hydrocracking zone 350 operating as a partialconversion hydrocracker using once-through configuration include 48-82,50-80, 48-75 or 50-75 wt % of effluent (relative to the feed to thehydrocracking zone 350 boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe unconverted oil fraction, all or a portion of which can beeffectively integrated as feed to the gas oil steam cracking zone 250 asdescribed herein.

FIG. 11 schematically depicts another embodiment of an integratedhydrocracking unit operation, a two-stage with recycle hydrocrackingzone 370, which operates as two-stage hydrocracking system with recycle.In general, hydrocracking zone 370 includes a first reaction zone 372, asecond reaction zone 382 and a fractionating zone 342.

First reaction zone 372 generally includes one or more inlets in fluidcommunication with a source of initial feedstock 334 and a source ofhydrogen gas 338. One or more outlets of the first reaction zone 372that discharge effluent stream 374 are in fluid communication with oneor more inlets of the fractionating zone 342 (optionally having one ormore high pressure and low pressure separation stages therebetween forrecovery of recycle hydrogen, not shown).

Fractionating zone 342 includes one or more outlets for discharginggases 344, typically H₂S, NH₃, and light hydrocarbons (C1-C4); one ormore outlets for recovering product 346, such as naphtha and dieselproducts boiling in the temperature range including and belowatmospheric gas oil range fractions (for instance in the temperaturerange of 36-370° C.); and one or more outlets for discharging bottoms348 including hydrocarbons boiling above the atmospheric gas oil range(for instance about 370° C.), from which a bleed stream 368 is obtainedin processes that do not operate with 100% recycle. In certainembodiments, the temperature cut point for bottoms 348 (andcorrespondingly the end point for the products 346) is a rangecorresponding to the upper temperature limit of the desired gasoline,kerosene and/or diesel product boiling point ranges for downstreamoperations.

The fractionating zone 342 bottoms outlet is in fluid communication withthe one or more inlets of the second reaction zone 382 for recyclestream 348 a derived from the bottoms stream 348. Recycle stream 348 acan be all or a portion of the bottoms stream 348. In certain optionalembodiments (as indicated by dashed lines in FIG. 11), a portion 348 bis in fluid communication with one or more inlets of the first reactionzone 372.

Second reaction zone 382 generally includes one or more inlets in fluidcommunication with the fractionating zone 342 bottoms outlet portion 348a of bottoms 348, and a source of hydrogen gas 384. One or more outletsof the second reaction zone 382 that discharge effluent stream 386 arein fluid communication with one or more inlets of the fractionating zone342 (optionally having one or more high pressure and low pressureseparation stages therebetween for recovery of recycle hydrogen, notshown).

In operation of the two-stage hydrocracking zone 370, a feedstock stream334 and a hydrogen stream 338 are charged to the first reaction zone372. Hydrogen stream 338 is an effective quantity of hydrogen to supportthe requisite degree of hydrocracking, feed type, and other factors, andcan be any combination including, recycle hydrogen 336 from optional gasseparation subsystems (not shown) associated with reaction zones 372 and382, and/or derived from fractionator gas stream 344 and make-uphydrogen 302. In certain embodiments, a reaction zone can containmultiple catalyst beds and can receive one or more quench hydrogenstreams between the beds (not shown).

First reaction zone 372 operates under effective conditions forproduction of reaction effluent stream 374 which is passed to thefractionating zone 342 (optionally after one or more high pressure andlow pressure separation stages to recover recycle hydrogen) generally torecover gas and liquid products and by-products, and separate a bottomsfraction.

Gas stream 344, typically containing H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄), is discharged and recovered and can be furtherprocessed. Effluent off-gases are passed to the olefins recovery train,the saturated gas plant as part of the other gases stream 156, and/ordirectly to a fuel gas system. Liquefied petroleum gas can be recoveredand routed to the mixed feed steam cracking zone, the olefins recoverytrain and/or the saturated gas plant. One or more cracked productstreams 346 are discharged via appropriate outlets of the fractionatorand can be further processed and/or blended in downstream refineryoperations to produce gasoline, kerosene and/or diesel fuel, or otherpetrochemical products. In certain embodiments, a diesel fraction 376derived from the one or more cracked product streams 346 can beintegrated with the feed to the second stage reactor 382. Thisintegration adds to the flexibility of the configuration betweenproduction of diesel fuel or petrochemicals from the product streams346.

In certain embodiments (not shown), fractionating zone 342 can operateas a flash vessel to separate heavy components at a suitable cut point,for example, a range corresponding to the upper temperature range of thedesired gasoline, kerosene and/or diesel products for downstreamoperations. In certain embodiments, a suitable cut point is in the rangeof 350 to 450° C., 360 to 450° C., 370 to 450° C., 350 to 400° C., 360to 400° C., 370 to 400° C., 350 to 380° C., or 360 to 380° C. The streamabove that cut point is routed to the gas oil steam cracking zone 250 asdescribed herein.

All or a portion of the fractionator bottoms stream 348 from thereaction effluent is passed to the second reaction zone 382 as stream348 a. In certain embodiments, all or a portion of the bottoms stream348 is recycled to the second reaction zone 382 as stream 348 a, thefirst reaction zone 372 as stream 348 b, or both the first and secondreaction zones 372 and 382. For instance, stream 348 b which is recycledto zone 372 comprises 0 to 100 vol %, 0 to about 80 vol %, or 0 to about50 vol % of stream 348, and stream 348 a which is recycled to zone 382comprises 0 to 100 vol %, 0 to about 80 vol %, or 0 to about 50 vol % ofstream 348. In certain embodiments, in which the recycle is at orapproaches 100 vol %, recycle of the unconverted oil increases the yieldof products suitable as feed to the mixed feed steam cracking zone 230.

In certain embodiments, a portion of the fractionator bottoms from thereaction effluent is removed as bleed stream 368. Bleed stream 368 canbe about 0-10 vol %, 1-10 vol %, 1-5 vol % or 1-3 vol % of thefractionator bottoms 348.

Second reaction zone 382 operates under conditions effective forproduction of the reaction effluent stream 386, which containsconverted, partially converted and unconverted hydrocarbons. The secondstage the reaction effluent stream 386 is passed to the fractionatingzone 342, optionally through one or more gas separators to recoveryrecycle hydrogen and remove certain light gases

For instance, a suitable two-stage hydrocracking zone 370 can include,but is not limited to, systems based on technology commerciallyavailable from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US;Axens, IFP Group Technologies, FR; or Shell Global Solutions, US.

The reactor arrangement in the two-stage with recycle hydrocracking zone370 can contain one or more fixed-bed, ebullated-bed, slurry-bed, movingbed, continuous stirred tank (CSTR), or tubular reactors, which can bein parallel arrangement. Additional equipment, including exchangers,furnaces, feed pumps, quench pumps, and compressors to feed thereactor(s) and maintain proper operating conditions, are well known andare considered part of the two-stage hydrocracking zone 370. Inaddition, equipment, including pumps, compressors, high temperatureseparation vessels, low temperature separation vessels and the like toseparate reaction products and provide hydrogen recycle within thetwo-stage hydrocracking zone 370, are well known and are considered partof the two-stage hydrocracking zone 370.

In certain embodiments, operating conditions for the first stagereactor(s) in hydrocracking zone 370 using a two-stage with recycleconfiguration operating in a full conversion mode of operation include:

a reactor inlet temperature (° C.) in the range of from about 340-502,340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 350-516,350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 100-180,100-160, 100-141, 121-180, 121-160, 121-141, 128-180, 128-160, 128-141or 131-180;

a reaction outlet pressure (barg) in the range of from about 90-170,90-137, 90-130, 112-170, 112-137, 112-130, 118-150, 118-137 or 118-170;

a hydrogen partial pressure (barg) (outlet) in the range of from about90-137, 90-106, 90-120, 100-137, 100-106, or 100-120;

a hydrogen treat gas feed rate (SLt/Lt) up to about 1050, 940, 898 or876, in certain embodiments from about 769-940, 769-898, 769-876,812-940, 812-898, 812-876, 834-940, 834-898, or 834-876;

a hydrogen quench gas feed rate (SLt/Lt) up to about 1100, 980, 935 or913, in certain embodiments from about 801-980, 801-935, 801-913,846-980, 846-935, 846-913, 868-980, 868-935, or 868-913;

make-up hydrogen rate (SLt/Lt) up to about 564, 512, 490 or 468, incertain embodiments from about 378-512, 378-490, 378-468, 401-512,401-490, 401-468, 423-512, 423-490, or 423-468; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0,0.4-5.0, 0.4-2.0 or 0.5-1.5.

In certain embodiments, operating conditions for the second stagereactor(s) in hydrocracking zone 370 using a two-stage with recycleconfiguration operating in a full conversion mode of operation include:

In certain embodiments, operating conditions for the reactor(s) in thefirst stage reaction zone of the two-stage hydrocracking zone 370include:

a reactor inlet temperature (° C.) in the range of from about 340-502,340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440or 412-420;

a reactor outlet temperature (° C.) in the range of from about 350-516,350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450or 422-430;

a start of run (SOR) reaction temperature, as a weighted average bedtemperature (WABT), in the range of from about 310-475, 310-435,310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or390-397;

an end of run (EOR) reaction temperature, as a WABT, in the range offrom about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450,400-516, 400-471, 400-450 or 422-430;

a reaction inlet pressure (barg) in the range of from about 80-145,80-100, 80-131, 80-120, 120-145, 100-145, or 130-145;

a reaction outlet pressure (barg) in the range of from about 75-137,75-130, 90-130, 100-137, 100-122, or 112-137;

a hydrogen partial pressure (barg) (outlet) in the range of from about90-145, 90-106, 90-120, 100-145, 100-106, or 100-120;

a hydrogen treat gas feed rate (SLt/Lt) up to about 910, 823, 785 or767, in certain embodiments from about 673-823, 673-785, 673-767,711-823, 711-785, 711-767, 729-823, 729-785, or 729-767;

a hydrogen quench gas feed rate (SLt/Lt) up to about 980, 882, 842 or822, in certain embodiments from about 721-882, 721-842, 721-822,761-882, 761-842, 761-822, 781-882, 781-842, or 781-822;

make-up hydrogen rate (SLt/Lt) up to about 451, 410, 392 or 374, incertain embodiments from about 303-410, 303-392, 303-374, 321-410,321-392, 321-374, 338-410, 338-392, or 338-374; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrocracking catalysts, are in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 1.0-5.0, 2.0-4.0 or1.0-3.0.

Under the above conditions and catalyst selections, exemplary productsfrom the hydrocracking zone 370 operating as a two-stage hydrocracker(with recycle) in a full conversion mode include 78-99, 78-90, 78-85,80-90 or 80-99 wt % of effluent (relative to the feed to thehydrocracking zone 370) boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe unconverted oil fraction, all or a portion of which can beeffectively integrated as feed to the gas oil steam cracking zone 250 asdescribed herein.

In a hydrotreating mode of operation, as shown in FIG. 8, a vacuum gasoil hydrotreating zone 300 operates under suitable hydrotreatingconditions, and generally produces off-gas and light ends (not shown), awild naphtha stream 306 and hydrotreated gas oil stream 304. In certainembodiments, instead of or in conjunction with the naphtha stream 306, ahydrotreated distillates stream 308 is recovered and passed to thediesel hydrotreating zone 180. Effluent off-gases are recovered from thegas oil hydrotreating zone 300 and are passed to the olefins recoverytrain, the saturated gas plant as part of the other gases stream 156,and/or directly to a fuel gas system. Liquefied petroleum gas can berecovered from the gas oil hydrotreating zone 300 and routed to themixed feed steam cracking zone, the olefins recovery train and/or thesaturated gas plant. The naphtha fraction 306 is routed to the mixedfeed steam cracking zone 230. In certain embodiments, the hydrotreatednaphtha fraction 306 is routed through the crude complex 100, alone, orin combination with other wild naphtha fractions from within theintegrated process. In embodiments in which hydrotreated naphthafraction 306 is routed through the crude complex 100, all or a portionof the liquefied petroleum gas produced in the gas oil hydrotreatingzone 300 can be passed with the hydrotreated naphtha fraction 306.Hydrotreated gas oil 304 is routed to the gas oil steam cracking zone250. In certain embodiments, in addition to or in conjunction with thehydrotreated naphtha fraction 306, all or a portion of the hydrotreateddistillates and naphtha from the gas oil hydrotreating zone 300 arepassed to the diesel hydrotreating zone 180.

The gas oil hydrotreating zone 300 can operate under mild, moderate orsevere conditions, depending on factors including the feedstock and thedesired degree of conversion. Such conditions are effective for removalof a significant amount of the sulfur and other known contaminants, andfor conversion of the feed(s) into a major proportion of hydrotreatedgas oil 304 that is passed to the gas oil steam cracking zone 250, andminor proportions of off-gases, light ends, and hydrotreated naphtha 306that is routed to the mixed feed steam cracking zone 230 (optionally viathe crude complex 100). The hydrotreated gas oil fraction 304 generallycontains the portion of the gas oil hydrotreating zone 300 effluent thatis at or above the AGO, H-AGO or VGO range.

For instance, a suitable gas oil hydrotreating zone 300 can include, butis not limited to, systems based on technology commercially availablefrom Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFPGroup Technologies, FR; or Shell Global Solutions, US.

The gas oil hydrotreating zone 300 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the gas oilhydrotreating zone 300. In addition, equipment, including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the gas oil hydrotreating zone 300, arewell known and are considered part of the gas oil hydrotreating zone300.

An effective quantity of catalyst is provided in gas oil hydrotreatingzone 300, including those possessing hydrotreating functionality, forhydrodesulfurization and hydrodenitrification. Such catalyst generallycontain one or more active metal component of metals or metal compounds(oxides or sulfides) selected from the Periodic Table of the ElementsIUPAC Groups 6-10. In certain embodiments, the active metal component isone or more of Co, Ni, W and Mo. The active metal component is typicallydeposited or otherwise incorporated on a support, such as amorphousalumina, amorphous silica alumina, zeolites, or combinations thereof. Incertain embodiments, the catalyst used in the gas oil hydrotreating zone300 includes one or more beds selected from Co/Mo, Ni/Mo, Ni/W, andCo/Ni/Mo. Combinations of one or more beds of Co/Mo, Ni/Mo, Ni/W andCo/Ni/Mo, can also be used. The combinations can be composed ofdifferent particles containing a single active metal species, orparticles containing multiple active species. In certain embodiments, acombination of Co/Mo catalyst and Ni/Mo catalyst are effective forhydrodesulfurization and hydrodenitrification. One or more series ofreactors can be provided, with different catalysts in the differentreactors of each series. For instance, a first reactor includes Co/Mocatalyst and a second reactor includes Ni/Mo catalyst. Suitable catalystused in the gas oil hydrotreating zone 300 have an expected lifetime inthe range of about 28-44, 28-38, 34-44 or 34-38 months.

In certain embodiments, the gas oil hydrotreating zone 300 operatingconditions include:

a reactor inlet temperature (° C.) in the range of from about 324-496,324-453, 324-431, 367-496, 367-453, 367-431, 389-496, 389-453, 389-431or 406-414;

a reactor outlet temperature (° C.) in the range of from about 338-516,338-471, 338-449, 382-516, 382-471, 382-449, 404-516, 404-471, 404-449or 422-430;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 302-462, 302-422,302-402, 342-462, 342-422, 342-402, 362-462, 362-422, 362-402 or378-384;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 333-509, 333-465, 333-443, 377-509, 377-465, 377-443,399-509, 399-465, 399-443 or 416-424;

a reaction inlet pressure (barg) in the range of from about 91-137,91-125, 91-119, 102-137, 102-125, 102-119, 108-137, 108-125, 108-119 or110-116;

a reaction outlet pressure (barg) in the range of from about 85-127,85-117, 85-111, 96-127, 96-117, 96-111, 100-127, 100-117 or 100-111;

a hydrogen partial pressure (barg) (outlet) in the range of from about63-95, 63-87, 63-83, 71-95, 71-87, 71-83, 75-95, 75-87, 75-83 or 77-81;

a hydrogen treat gas feed rate (SLt/Lt) up to about 525, 510, 465 or445, in certain embodiments from about 335-510, 335-465, 335-445,380-510, 380-465, 380-445, 400-510, 400-465 or 400-445;

a hydrogen quench gas feed rate (SLt/Lt) up to about 450, 430, 392 or375, in certain embodiments from about 285-430, 285-392, 285-375,320-430, 320-392, 320-375, 338-430, 338-392 or 338-375;

a make-up hydrogen feed rate (SLt/Lt) up to about 220, 200, 180 or 172,in certain embodiments from about 130-200, 130-180, 130-172, 148-200,148-180, 148-172, 155-200, 155-180 or 155-172; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrotreating catalysts, in the range of from about0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0,0.4-5.0, 0.4-3.0 or 0.5-2.5.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrotreating zone 300 include 1-30, 5-30, 2-27 or 5-27wt % of effluent (relative to the feed to the gas oil hydrotreating zone300) boiling at or below the atmospheric residue end boiling point, suchas 370° C., including LPG, kerosene, naphtha, and atmospheric gas oilrange components. The remaining bottoms fraction is the hydrotreated gasoil fraction, all or a portion of which can be effectively integrated asfeed to the gas oil steam cracking zone 250 as described herein.

In additional embodiments, the gas oil hydrotreating zone 300 canoperate under conditions effective for feed conditioning and to maximizetargeted conversion to petrochemicals in the steam cracker complex.Accordingly, in certain embodiments severity conditions are selectedthat achieve objectives differing from those used for conventionalrefinery operations. That is, while typical VGO hydrotreating operateswith less emphasis on conservation of liquid product yield, in thepresent embodiment VGO hydrotreating operates to produce a higher yieldof lighter products which are intentionally recovered to maximizechemicals yield. In embodiments to maximize conversion topetrochemicals, the gas oil hydrotreating zone 300 operating conditionsinclude:

a reactor inlet temperature (° C.) in the range of from about 461-496,461-473, 485-496 or 473-485;

a reactor outlet temperature (° C.) in the range of from about 480-516,480-489, 489-495 or 495-516;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 430-462, 430-440,440-450 or 450-462;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 473-509, 484-495, 473-484 or 495-509;

a reaction inlet pressure (barg) in the range of from about 110-137,113-137, 110-120, 120-129 or 129-137;

a reaction outlet pressure (barg) in the range of from about 104-118,104-108, 112-118 or 108-112;

a hydrogen partial pressure (barg) (outlet) in the range of from about76-95, 76-83, 83-89, or 89-95;

a hydrogen treat gas feed rate (SLt/Lt) up to about 525, 485, 490 or520, in certain embodiments from about 474-520, 474-488, 488-500, or500-520;

a hydrogen quench gas feed rate (SLt/Lt) up to about 450, 441, 416 or429, in certain embodiments from about 400-441, 400-415, 415-430, or430-441;

a make-up hydrogen feed rate (SLt/Lt) up to about 220, 200, 207 or 214,in certain embodiments from about 186-200, 190-200, 186-190, 190-195, or195-200; and

liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrotreating catalysts, in the range of from about0.5-0.7, 0.5-0.55, 0.55-0.6, 0.6-0.65, 0.65-0.7.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrotreating zone 300 operating under conditionseffective for feed conditioning and to maximize targeted conversion topetrochemicals in the steam cracker complex include 20-30, 22-28, 23-27or 24-26 wt % of effluent (relative to the feed to the gas oilhydrotreating zone 300) boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe hydrotreated gas oil fraction, all or a portion of which can beeffectively integrated as feed to the gas oil steam cracking zone 250 asdescribed herein.

In certain embodiments, the gas oil hydrotreating zone 300 contains oneor more trains of reactors, with a first reactor having two catalystbeds with two quench streams including an inter-bed quench stream, and asecond reactor (lag reactor) having one catalyst bed with a quenchstream. In high capacity operations, two or more parallel trains ofreactors are utilized. In such embodiments, the flow in gas oilhydrotreating zone 300 is split after the feed pump into paralleltrains, wherein each train contains feed/effluent heat exchangers, feedheater, a reactor and the hot separator. The trains recombine after thehot separators. Tops from the hot separators are combined and passed toa cold separator. Bottoms from the hot separators are passed to a hotflash drum. Bottoms from the cold separator and tops from the hot flashdrum are passed to a low pressure flash drum to remove off-gases. Hotflash liquid bottoms and low pressure flash bottoms are passed to astripper to recover hydrotreated gas oil and wild naphtha. Tops from thecold separator are subjected to absorption and amine scrubbing. Recyclehydrogen is recovered, and passed (along with make-up hydrogen) to thereaction zone as treat gas and quench gas.

The vacuum residue from the vacuum distillation zone is processed in adelayed coking zone. The delayed coking zone produces a coker naphthastream, a coker gas oil stream and petroleum coke. Some or all of thecoker naphtha can be routed to the aromatics extraction zone and/or themixed feed steam cracking zone. In certain embodiments, some or all ofthe coker gas oil is sent to a vacuum gas oil hydroprocessing zone.Liquefied petroleum gas can be recovered from delayed coking unit androuted to the mixed feed steam cracking zone, the olefins recovery trainand/or the saturated gas plant.

Coking is a carbon rejection process in which low-value atmospheric orvacuum distillation bottoms are converted to lighter products which inturn can be hydrotreated to produce transportation fuels such asgasoline and diesel, and increments of light products which can befurther desulfurized, treated, and/or concentrated to produce chemicals.Conventionally, coking of residuum from heavy high sulfur, or sour,crude oils is carried out primarily as a means of utilizing such lowvalue hydrocarbon streams by converting part of the material to morevaluable liquid and gas products. Typical coking processes includedelayed coking and fluid coking.

In the delayed coking process, feedstock is typically introduced into alower portion of a coking feed fractionator where one or more lightermaterials are recovered as one or more top fractions, and bottoms arepassed to a coking furnace. In the furnace bottoms from the fractionatorand optionally heavy recycle material are mixed and rapidly heated in acoking furnace to a coking temperature, e.g., in the range of 480° C. to530° C., and then fed to a coking drum. The hot mixed fresh and recyclefeedstream is maintained in the coke drum at coking conditions oftemperature and pressure where the feed decomposes or cracks to formcoke and volatile components.

The volatile components are recovered as vapor and transferred to acoking product fractionator. One or more heavy fractions of the cokedrum vapors can be condensed, e.g. quenching or heat exchange. Incertain embodiments the coke drum vapors are contacted with heavy gasoil in the coking unit product fractionator, and heavy fractions formall or part of a recycle oil stream having condensed coking unit productvapors and heavy gas oil. In certain embodiments, heavy gas oil from thecoking feed fractionator is added to the flash zone of the fractionatorto condense the heaviest components from the coking unit product vapors.

Coking units are typically configured with two or more parallel drumsand operated in an alternating swing mode if there are two drums, or ina sequentially cyclic operating mode if there are three or more drums.Parallel coking drum trains, with two or more drums per train, are alsopossible. When the coke drum is full of coke, the feed is switched toanother drum, and the full drum is cooled. Liquid and gas streams fromthe coke drum are passed to a coking product fractionator for recovery.Any hydrocarbon vapors remaining in the coke drum are removed by steaminjection. The coke remaining in the drum is typically cooled with waterand then removed from the coke drum by conventional methods, e.g., usinghydraulic and/or mechanical techniques to remove green coke from thedrum walls for recovery.

In certain embodiments, one or more catalysts and additives can be addedto the fresh feed and/or the fresh and recycle oil mixture prior toheating the feedstream in the coking unit furnace. The catalyst canpromote cracking of the heavy hydrocarbon compounds and promoteformation of the more valuable liquids that can be subjected tohydrotreating processes downstream to form transportation fuels. Thecatalyst and any additive(s) remain in the coking unit drum with thecoke if they are solids, or are present on a solid carrier. If thecatalyst(s) and/or additive(s) are soluble in the oil, they are carriedwith the vapors and remain in the liquid products. Note that in theproduction of high quality petroleum green coke, catalyst(s) and/oradditive(s) which are soluble in the oil can be favored in certainembodiments to minimize contamination of the coke.

In the embodiments of FIG. 7, all or a portion of the vacuum residuestream 168 is charged to a delayed coking unit 900. all, a substantialportion, a significant portion or a major portion of the vacuum residuestream 168 can be processed in the delayed coking unit 900, in certainembodiments in conjunction with other feeds such as all or a portion ofpyrolysis oil (shown as stream 902), or atmospheric residue (not shown).In certain embodiments, coking unit 900 is a delayed coker unit. Anembodiment of the delayed coking zone 900 is shown in FIG. 12. Thedelayed coking zone 900 generally produces a coker naphtha stream 922, acoker gas oil stream 904 and petroleum coke 910, which is recovered. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the coker gas oil stream 904 is sent to the gasoil hydroprocessing zone, as contains a relatively high content ofheteroatoms such as sulfur, and metals such as Ni, V. Effluent off-gasesand light ends (not shown) are recovered from the delayed coking unit900 can be routed to the olefins recovery train, a gas plant such as theplant 150 as part of the other gases stream 156 or an unsaturated gasplant (not shown), and/or to the cracker complex recovery section. Incertain embodiments, some or all of the coker naphtha stream 922 is sentto a coker naphtha hydrotreater 924, and the effluent can be routed tothe aromatics extraction zone 620, the mixed feed steam cracker 230, thecrude complex 100, or any combination of the aromatics extraction zone620 and the mixed feed steam cracker 230.

The vacuum residue stream 168 is charged to a coking furnace 912 wherethe contents are rapidly heated to a coking temperature, for example, inthe range of about 480-530° C., and then fed to a coking drum 914 or916. Coking unit 900 can be configured with two or more parallel drums914 and 916 and can be operated in a swing mode, such that when one ofthe drums is filled with coke, vacuum residue stream 168 is transferredto the empty parallel drum so that accumulated coke 910 can be recoveredfrom the filled drum. Liquid and gas stream 918 from the coker drum 914or 916 are fed to a coking product fractionator 920. Any hydrocarbonvapors remaining in the coke drum are removed by steam injection. Thecoke is cooled with water and then removed from the coke drum usinghydraulic and/or mechanical means.

Liquid and gas coking unit product stream 918 is introduced into acoking product stream fractionator 920. The coking product stream 918 isfractionated to yield separate product streams that can include a cokernaphtha stream 922, and a coker gas oil stream 904 which is recoveredfrom the fractionator. In certain embodiments, some or all of the cokergas oil stream 904 is sent to the vacuum gas oil hydroprocessing zone.Effluent off-gases are recovered from the delayed coking unit 900 andare passed to the olefins recovery train, an unsaturated gas plant,and/or directly to a fuel gas system. Liquefied petroleum gas can berecovered from delayed coking unit 900 and routed to the mixed feedsteam cracking zone, the olefins recovery train and/or the unsaturatedgas plant. In certain embodiments, some or all of the coker naphthastream 922 is sent to a coker naphtha hydrotreater 924 for furthertreatment because it generally contains heavy metals and about 10-20times the amount of sulfur that a straight run naphtha and is notsuitable for processing in other refinery units such as the mixed feedsteam cracking zone 230 or other hydrotreaters.

Due to its high metal and sulfur content, the coker naphtha stream 922is processed in a coker naphtha hydrotreating zone 924, in the presenceof an effective amount of hydrogen obtained from recycle within thecoker naphtha hydrotreating zone 924 and make-up hydrogen 926. The cokernaphtha hydrotreating zone 924 is understood to be a part of 900 inFIGS. 1, 2, 7, 8, 15 and 16. In FIG. 12, the coker naphtha hydrotreatingzone 924 is shown in more detail. In certain embodiments, all or aportion of the make-up hydrogen 926 is derived from the steam crackerhydrogen stream 210 from the olefins recovery train 270. In certainembodiments all or a portion of the pyrolysis fuel oil streams 236, 256is fed to the delayed coking zone 900, shown as streams 902.

A suitable coker naphtha hydrotreating zone 924 can include, but is notlimited to, systems based on technology commercially available fromHoneywell UOP, US; Chevron Lummus Global LLC (CLG), US; or Axens, IFPGroup Technologies, FR.

The effluent from the coker naphtha hydrotreating zone 924 generallycontain C5-C9+ hydrocarbons, or in certain embodiments C6-C9+hydrocarbons, recovered as a hydrotreated coker naphtha stream 908. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the hydrotreated coker naphtha stream 908 ispassed to the mixed feed steam cracking zone 230, directly, or throughthe crude complex 100. In certain embodiments, all, a substantialportion, a significant portion or a major portion of the hydrotreatedcoker naphtha stream 908 is passed to the aromatics extraction zone 620for recovery of BTX streams. In certain embodiments, the full range ofC5-C9+ hydrocarbons in the hydrotreated coker naphtha stream 908 arepassed to the aromatics extraction zone 620, and the aromaticsextraction zone 620 includes a depentanizing step to remove C5s forrecycle to the mixed feed steam cracking zone 230. In other embodimentsa coker naphtha hydrotreating zone 924 includes a depentanizing step(not shown) to remove C5s as stream 906; all, a substantial portion, asignificant portion or a major portion of stream 906 is passed to themixed feed steam cracking zone 230; and all, a substantial portion, asignificant portion or a major portion of the hydrotreated coker naphthastream 908, generally containing C6-C9+ hydrocarbons, is passed to thearomatics extraction zone 620.

The coker naphtha hydrotreating zone 924 can contain one or morefixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirredtank (CSTR) or tubular reactors, in series and/or parallel arrangement.Additional equipment, including exchangers, furnaces, feed pumps, quenchpumps, and compressors to feed the reactor(s) and maintain properoperating conditions, are well known and are considered part of thecoker naphtha hydrotreating zone 924. In addition, equipment, includingpumps, compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the coker naphtha hydrotreating zone924, are well known and are considered part of the coker naphthahydrotreating zone 924.

The coker naphtha hydrotreating zone 924 is operated under conditionseffective to treat coker naphtha to produce hydrotreated coker naphtha908. In certain embodiments all, a substantial portion, a significantportion or a major portion of the hydrotreated coker naphtha 908 can beused as additional feed to the aromatics extraction zone 620, and anyremainder can be used for fuel production. In certain embodiments aportion 908 a of the hydrotreated coker naphtha can be used for fuelproduction.

In certain embodiments, the coker naphtha hydrotreating zone 924operating conditions include:

a reactor inlet temperature (° C.) in the range of from about 293-450,293-410, 293-391, 332-450, 332-410, 332-391, 352-450, 352-410, 352-391or 368-374;

a reactor outlet temperature (° C.) in the range of from about 316-482,316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378-420or 396-404;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 284-436, 284-398,284-379, 322-436, 322-398, 322-379, 341-436, 341-398, 341-379 or357-363;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420,378-482, 378-441, 378-420 or 396-404;

a reaction inlet pressure (barg) in the range of from about 44-66,44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60, 52-58 or 53-56;

a reaction outlet pressure (barg) in the range of from about 39-58,39-53, 39-51, 43-58, 43-53, 43-51, 46-58, 46-53 or 46-51;

a hydrogen partial pressure (barg) (outlet) in the range of from about22-33, 22-30, 22-29, 25-33, 25-30, 25-29, 26-33, 26-30 or 26-29;

a hydrogen treat gas feed rate (SLt/Lt) up to about 640, 620, 570 or542, in certain embodiments from about 413-620, 413-570, 413-542,465-620, 465-570, 465-542, 491-620, 491-570 or 491-542;

a hydrogen quench gas feed rate (SLt/Lt) up to about 95, 85, 78 or 75,in certain embodiments from about 57-85, 57-78, 57-75, 64-85, 64-78,64-75, 68-85, 68-78 or 68-75; and

a make-up hydrogen feed rate (SLt/Lt) up to about 120, 110 or 102, incertain embodiments from about 78-120, 78-110, 78-102, 87-120, 87-110,87-102, 92-120, 92-110, 92-102 or 95-100.

An effective quantity of hydrotreating catalyst is provided in the cokernaphtha hydrotreating zone 924, including those possessing hydrotreatingfunctionality and which generally contain one or more active metalcomponent of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 6-10. In certainembodiments, the active metal component is one or more of Co, Ni, W andMo. The active metal component is typically deposited or otherwiseincorporated on a support, such as amorphous alumina, amorphous silicaalumina, zeolites, or combinations thereof. In certain embodiments, thecatalyst used in the coker naphtha hydrotreating zone 924 includes oneor more catalyst selected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo.Combinations of one or more of Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo, can alsobe used. The combinations can be composed of different particlescontaining a single active metal species, or particles containingmultiple active species. In certain embodiments, Co/Mohydrodesulfurization catalyst is suitable. Effective liquid hourly spacevelocity values (h⁻¹), on a fresh feed basis relative to thehydrotreating catalysts, are in the range of from about 0.1-10.0,0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0or 0.8-1.2. Suitable hydrotreating catalysts used in the coker naphthahydrotreating zone 924 have an expected lifetime in the range of about28-44, 34-44, 28-38 or 34-38 months.

The mixed feed steam cracking zone 230, which operates as high severityor low severity thermal cracking process, generally converts LPG,naphtha and heavier hydrocarbons primarily into a mixed product stream232 containing mixed C1-C4 paraffins and olefins. In certainembodiments, the mixed feed steam cracking zone 230 processesstraight-run liquids from the crude unit, ethane and/or propane (fromoutside battery limits and/or recycled) and various recycle streams fromchemical production and recovery areas within the integrated process andsystem. A suitable mixed feed steam cracking zone 230 can include, butis not limited to, systems based on technology commercially availablefrom Linde AG, DE; TechnipFMC plc, UK; Chicago Bridge & Iron CompanyN.V. (CB&I), NL; or KBR, Inc, US.

For instance, plural feeds to the mixed feed steam cracking zone 230include: light ends 152, light naphtha 138 and heavy naphtha 140 (or afull range straight run naphtha 136 as shown in other embodiments) fromthe crude complex 100; a LPG stream 634 from a transalkylation zone 630;a recycle stream 282 from the methylacetylene/propadiene (MAPD)saturation and propylene recovery zone 280 described below; C4 raffinate524 from the 1-butene recovery zone 520 described below; wild naphtha184 from the diesel hydrotreating zone 180 described above (in certainembodiments via the crude complex); naphtha from the vacuum gas oilhydroprocessing zone described above (wild naphtha 326 or hydrotreatednaphtha 306) described above (in certain embodiments via the crudecomplex); a raffinate stream 646 from the aromatics extraction zone 620described below; in certain embodiments a C5 cut derived from thepyrolysis gasoline described below; in certain embodiments hydrotreatedcoker naphtha 908 from a coker hydrotreating unit described above; andoptionally, propane stream 228 (from outside battery limits. In certainembodiments, the mixed feed steam cracking zone 230 can accept alternatefeeds from other sources, for instance, other naphtha range feeds thatmay become available from outside of the battery limits.

The products from the mixed feed steam cracking zone 230 include: aquenched cracked gas stream 232 containing mixed C1-C4 paraffins andolefins that is routed to the olefins recovery zone 270; a raw pyrolysisgasoline stream 234 that is routed to a py-gas hydrotreating zone 600 toproduce hydrotreated pyrolysis gasoline 604 as feed to the aromaticsextraction zone 620, and C5s 606; and a pyrolysis fuel oil stream 236.

The mixed feed steam cracking zone 230 operates under parameterseffective to crack the feed into desired products including ethylene,propylene, butadiene, and mixed butenes. Pyrolysis gasoline andpyrolysis oil are also recovered. In certain embodiments, the steamcracking furnace(s) are operated at conditions effective to produce aneffluent having a propylene-to-ethylene weight ratio of from about0.3-0.8, 0.3-0.6, 0.4-0.8 or 0.4-0.6.

The mixed feed steam cracking zone 230 generally comprises one or moretrains of furnaces. For instance, a typical arrangement includesreactors that can operate based on well-known steam pyrolysis methods,that is, charging the thermal cracking feed to a convection section inthe presence of steam to raise the temperature of the feedstock, andpassing the heated feed to the pyrolysis reactor containing furnacetubes for cracking. In the convection section, the mixture is heated toa predetermined temperature, for example, using one or more waste heatstreams or other suitable heating arrangement.

The feed mixture is heated to a high temperature in a convection sectionand material with a boiling point below a predetermined temperature isvaporized. The heated mixture (in certain embodiments along withadditional steam) is passed to the pyrolysis section operating at afurther elevated temperature for short residence times, such as 1-2seconds or less, effectuating pyrolysis to produce a mixed productstream. In certain embodiments separate convection and radiant sectionsare used for different incoming feeds to the mixed feed steam crackingzone 230 with conditions in each optimized for the particular feed.

In certain embodiments, steam cracking in the mixed feed steam crackingzone 230 is carried out using the following conditions: a temperature (°C.) in the convection section in the range of about 400-600, 400-550,450-600 or 500-600; a pressure (barg) in the convection section in therange of about 4.3-4.8, 4.3-4.45, 4.3-4.6, 4.45-4.8, 4.45-4.6 or4.6-4.8; a temperature (° C.) in the pyrolysis section in the range ofabout 700-950, 700-900, 700-850, 750-950, 750-900 or 750-850; a pressure(barg) in the pyrolysis section in the range of about 1.0-1.4, 1.0-1.25,1.25-1.4, 1.0-1.15, 1.15-1.4 or 1.15-1.25; a steam-to-hydrocarbon ratioin the in the convection section in the range of about 0.3:1-2:1,0.3:1-1.5:1, 0.5:1-2:1, 0.5:1-1.5:1, 0.7:1-2:1, 0.7:1-1.5:1, 1:1-2:1 or1:1-1.5:1; and a residence time (seconds) in the pyrolysis section inthe range of about 0.05-1.2, 0.05-1, 0.1-1.2, 0.1-1, 0.2-1.2, 0.2-1,0.5-1.2 or 0.5-1.

In operation of the mixed feed steam cracking zone 230, effluent fromthe cracking furnaces is quenched, for instance, using transfer lineexchangers, and passed to a quench tower. The light products, quenchedcracked gas stream 232, are routed to the olefins recovery zone 270.Heavier products are separated in a hot distillation section. A rawpyrolysis gasoline stream is recovered in the quench system. Pyrolysisoil 236 is separated at a primary fractionator tower before the quenchtower.

In operation of one embodiment of the mixed feed steam cracking zone230, the feedstocks are mixed with dilution steam to reduce hydrocarbonpartial pressure and then are preheated. The preheated feeds are fed totubular reactors mounted in the radiant sections of the crackingfurnaces. The hydrocarbons undergo free-radical pyrolysis reactions toform light olefins ethylene and propylene, and other by-products. Incertain embodiments, dedicated cracking furnaces are provided withcracking tube geometries optimized for each of the main feedstock types,including ethane, propane, and butanes/naphtha. Less valuablehydrocarbons, such as ethane, propane, C4 raffinate, and aromaticsraffinate, produced within the integrated system and process, arerecycled to extinction in the mixed feed steam cracking zone 230.

In certain embodiments, cracked gas from the furnaces is cooled intransfer line exchangers (quench coolers), for example, producing 1800psig steam suitable as dilution steam. Quenched cracked gas enters aprimary fractionator associated with the mixed feed steam cracking zone230 for removal of pyrolysis fuel oil bottoms from lighter components.The primary fractionator enables efficient recovery of pyrolysis fueloil. Pyrolysis fuel oil is stripped with steam in a fuel oil stripper tocontrol product vapor pressure, and cooled. In addition, secondaryquench can be carried out by direct injection of pyrolysis fuel oil asquench oil into liquid furnace effluents. The stripped and cooledpyrolysis fuel oil can be sent to a fuel oil pool or product storage.The primary fractionator overhead is sent to a quench water tower;condensed dilution steam for process water treating, and raw pyrolysisgasoline, are recovered. Quench water tower overhead is sent to theolefins recovery zone 270, particularly the first compression stage. Rawpyrolysis gasoline is sent to a gasoline stabilizer to remove any lightends and to control vapor pressure in downstream pyrolysis gasolineprocessing. A closed-loop dilution steam/process water system isenabled, in which dilution steam is generated using heat recovery fromthe primary fractionator quench pumparound loops. The primaryfractionator enables efficient recovery of pyrolysis fuel oil due toenergy integration and pyrolysis fuel oil content in the light fractionstream.

The gas oil steam cracking zone 250 is operated under conditionseffective for conversion of its feeds into light olefins, pyrolysisgasoline and pyrolysis oil. As described herein feeds to the gas oilsteam cracking zone 250 include vacuum gas oil range products from thevacuum gas oil hydroprocessing zone, such as hydrotreated gas oil 304 orunconverted oil 324; and in certain embodiments all or a portion of thethird middle distillate stream 126, for instance, in the atmospheric gasoil range. In certain embodiments, the gas oil steam cracking zone 250can accept alternate feeds from other sources, for instance, other gasoil range feeds that may become available from outside of the batterylimits. Products from the gas oil steam cracking zone 250 include aquenched cracked gas stream 252 containing mixed C1-C4 paraffins andolefins that is routed to the olefins recovery zone 270, a raw pyrolysisgasoline stream 254 that is routed to a py-gas hydrotreating zone 600 toprovide additional feed 604 to the aromatics extraction zone 620, and apyrolysis fuel oil stream 256.

The gas oil steam cracking zone 250 operates under parameters effectiveto crack the feed into desired products including ethylene, propylene,butadiene, and mixed butenes. Pyrolysis gasoline and pyrolysis oil arealso recovered. In certain embodiments, the steam cracking furnace(s) inthe gas oil steam cracking zone 250 are operated at conditions effectiveto produce an effluent having a propylene-to-ethylene weight ratio offrom about 0.3-0.8, 0.3-0.6, 0.4-0.8 or 0.4-0.6.

In one embodiment of the gas oil steam cracking zone 250, hydrotreatedVGO feedstock is preheated and mixed with a dilution steam to reducehydrocarbon partial pressure in a convection section. Thesteam-hydrocarbon mixture is heated further and fed to tubular reactorsmounted in the radiant sections of the cracking furnaces. Thehydrocarbons undergo free-radical pyrolysis reactions to form lightolefins, ethylene and propylene, and other by-products.

In certain embodiments, steam cracking in the gas oil steam crackingzone 250 is carried out using the following conditions: a temperature (°C.) in the convection section in the range of about 300-450 or 300-400;a pressure (barg) in the convection section in the range of about7.2-9.7, 7.2-8.5, 7.2-7.7, 7.7-8.5, 7.7-9.7 or 8.5-9.7; a temperature (°C.) in the pyrolysis section in the range of about 700-850, 700-800,700-820, 750-850, 750-800 or 750-820; a pressure (barg) in the pyrolysissection in the range of about 0.9-1.2, 0.9-1.4, 0.9-1.6, 1.2-1.4,1.2-1.6 or 1.4-1.6; a steam-to-hydrocarbon ratio in the in theconvection section in the range of about 0.75:1-2:1, 0.75:1-1.5:1,0.85:1-2:1, 0.9:1-1.5:1, 0.9:1-2:1, 1:1-2:1 or 1:1-1.5:1; and aresidence time (seconds) in the pyrolysis section in the range of about0.02-1, 0.02-0.08, 0.02-0.5, 0.1-1, 0.1-0.5, 0.2-0.5, 0.2-1, or 0.5-1.

In certain embodiments, cracked gas from the gas oil steam cracking zone250 furnaces is quenched in transfer line exchangers by producing, forinstance, 1800 psig steam. Quenched gases are stripped with steam in aprimary fractionator. Lighter gases are recovered as the overheadproduct; a side-draw stream contains pyrolysis fuel oil. The primaryfractionator bottoms product is pyrolysis tar, which is cooled and sentto product storage. Pyrolysis fuel oil from the primary fractionator isstripped with steam in the pyrolysis fuel oil stripper, which separatespyrolysis gasoline as the overhead and pyrolysis fuel oil as the bottomsproduct. Gasoline in the primary fractionator overhead is condensed andcombined with gasoline from the pyrolysis fuel oil stripper before beingsent to a gasoline stabilizer. The gasoline stabilizer removes lightproducts in the overhead, while the stabilizer bottoms are sent to thepy-gas hydrotreater. C4 and lighter gases in the primary fractionatoroverhead are compressed, for instance, in two stages of compression,before entering an absorber, depropanizer and debutanizer.

Compression of C4 and lighter gases from both the mixed feed steamcracking zone 230 and the gas oil steam cracking zone 250 can be carriedout in certain embodiments in a common step, to reduce capital andoperating costs associated with compression, thereby increasingefficiencies in the integrated process herein. Accordingly, both the C4and lighter gas stream 232 and the C4 and lighter gas stream 252 arepassed to the olefins recovery zone 270.

In certain embodiments, cracked gas from the furnaces of both the mixedfeed steam cracking zone 230 and the gas oil steam cracking zone 250 aresubjected to common steps for quenching, recovery of pyrolysis gasoline,recovery of pyrolysis oil, and recovery of C4 and lighter gases. Forinstance, in one embodiment, the cracked gas from the furnaces of bothsteam cracking zones are combined cooled in transfer line exchangers(quench coolers), for example, producing 1800 psig steam suitable asdilution steam. Quenched cracked gas enters a primary fractionator forremoval of pyrolysis fuel oil bottoms from lighter components. Theprimary fractionator enables efficient recovery of pyrolysis fuel oil.Pyrolysis fuel oil is stripped with steam in a fuel oil stripper tocontrol product vapor pressure and cooled. In addition, secondary quenchcan be carried out by direct injection of pyrolysis fuel oil as quenchoil into liquid furnace effluents. The stripped and cooled pyrolysisfuel oil can be sent to a fuel oil pool or product storage. The primaryfractionator overhead is sent to a quench water tower; condenseddilution steam for process water treating, and raw pyrolysis gasoline,are recovered. Quench water tower overhead is sent to the olefinsrecovery zone 270, particularly the first compression stage. Rawpyrolysis gasoline is sent to a gasoline stabilizer to remove any lightends and to control vapor pressure in downstream pyrolysis gasolineprocessing. A closed-loop dilution steam/process water system isenabled, in which dilution steam is generated using heat recovery fromthe primary fractionator quench pumparound loops. The primaryfractionator enables efficient recovery of pyrolysis fuel oil due toenergy integration and pyrolysis fuel oil content in the light fractionstream.

The mixed product stream 232 effluent from the mixed feed steam crackingzone 230 and the mixed product stream 252 effluent from the gas oilsteam cracking zone 250 are shown as combined streams 220. Stream 220 isrouted to an olefins recovery zone 270. For instance, light productsfrom the quenching step, C4-, H₂ and H₂S, are contained in the mixedproduct stream 220 that is routed to the olefins recovery zone 270.Products include: hydrogen 210 that is used for recycle and/or passed tousers; fuel gas 208 that is passed to a fuel gas system; ethane 272 thatis recycled to the mixed feed steam cracking zone 230; ethylene 202 thatis recovered as product; a mixed C3 stream 286 that is passed to amethyl acetylene/propadiene saturation and propylene recovery zone 280;and a mixed C4 stream 206 that is passed to a butadiene extraction zone500.

The olefins recovery zone 270 operates to produce on-specification lightolefin (ethylene and propylene) products from the mixed product stream220. For instance, cooled gas intermediate products from the steamcracker is fed to a cracked gas compressor, caustic wash zone, and oneor more separation trains for separating products by distillation. Incertain embodiments two trains are provided. The distillation trainincludes a cold distillation section, wherein lighter products such asmethane, hydrogen, ethylene, and ethane are separated in a cryogenicdistillation/separation operation. The mixed C2 stream from the steamcracker contains acetylenes that are hydrogenated to produce ethylene inan acetylene selective hydrogenation unit. This system can also includeethylene, propane and/or propylene refrigeration facilities to enablecryogenic distillation.

In one embodiment, mixed product stream 232 effluent from the mixed feedsteam cracking zone 230 and the mixed product stream 252 effluent fromthe gas oil steam cracking zone 250 are passed through three to fivestages of compression. Acid gases are removed with caustic in a causticwash tower. After an additional stage of compression and drying, lightcracked gases are chilled and routed to a depropanizer. In certainembodiments light cracked gases are chilled with a cascaded two-levelrefrigeration system (propylene, mixed binary refrigerant) for cryogenicseparation. A front-end depropanizer optimizes the chilling train anddemethanizer loading. The depropanizer separates C3 and lighter crackedgases as an overhead stream, with C4s and heavier hydrocarbons as thebottoms stream. The depropanizer bottoms are routed to the debutanizer,which recovers a crude C4s stream 206 and any trace pyrolysis gasoline,which can be routed to the py-gas hydrotreating zone 600 (not shown).

The depropanizer overhead passes through a series of acetyleneconversion reactors, and is then fed to the demethanizer chilling train,which separates a hydrogen-rich product via a hydrogen purificationsystem, such as pressure swing adsorption. Front-end acetylenehydrogenation is implemented to optimize temperature control, minimizegreen oil formation and simplify ethylene product recovery byeliminating a C2 splitter pasteurization section that is otherwisetypically included in product recovery. In addition, hydrogenpurification via pressure swing adsorption eliminates the need for amethanation reactor that is otherwise typically included in productrecovery.

The demethanizer recovers methane in the overhead for fuel gas, and C2and heavier gases in the demethanizer bottoms are routed to thedeethanizer. The deethanizer separates ethane and ethylene overheadwhich feeds a C2 splitter. The C2 splitter recovers ethylene product202, in certain embodiments polymer-grade ethylene product, in theoverhead. Ethane 272 from the C2 splitter bottoms is recycled to themixed feed steam cracking zone 230. Deethanizer bottoms contain C3s fromwhich propylene product 204, in certain embodiments polymer-gradepropylene product, is recovered as the overhead of a C3 splitter, withpropane 282 from the C3 splitter bottoms recycled to the mixed feedsteam cracking zone 230.

A methyl acetylene/propadiene (MAPD) saturation and propylene recoveryzone 280 is provided for selective hydrogenation to convert methylacetylene/propadiene, and to recover propylene from a mixed C3 stream286 from the olefins recovery zone 270. The mixed C3 286 from theolefins recovery zone 270 contains a sizeable quantity of propadiene andpropylene. The methyl acetylene/propadiene saturation and propylenerecovery zone 280 enables production of propylene 204, which can bepolymer-grade propylene in certain embodiments.

The methyl acetylene/propadiene saturation and propylene recovery zone280 receives hydrogen 284 and mixed C3 286 from the olefins recoveryzone 270. Products from the methyl acetylene/propadiene saturation andpropylene recovery zone 280 are propylene 204 which is recovered, andthe recycle C3 stream 282 that is routed to the steam cracking zone 230.In certain embodiments, hydrogen 284 to saturate methyl acetylene andpropadiene is derived from hydrogen 210 obtained from the olefinsrecovery zone 270.

A stream 206 containing a mixture of C4s, known as crude C4s, from theolefins recovery zone 270, is routed to a butadiene extraction zone 500to recover a high purity 1,3-butadiene product 502 from the mixed crudeC4s. In certain embodiments (not shown), a step of hydrogenation of themixed C4 before the butadiene extraction zone 500 can be integrated toremove acetylenic compounds, for instance, with a suitable catalytichydrogenation process using a fixed bed reactor. 1,3-butadiene 502 isrecovered from the hydrogenated mixed C4 stream by extractivedistillation using, for instance, n-methyl-pyrrolidone (NMP) ordimethylformamide (DMF) as solvent. The butadiene extraction zone 500also produces a raffinate stream 504 containing butane/butene, which ispassed to a methyl tertiary butyl ether zone 510.

In one embodiment, in operation of the butadiene extraction zone 500,the stream 206 is preheated and vaporized into a first extractivedistillation column, for instance having two sections. NMP or DMFsolvent separates the 1,3-butadiene from the other C4 componentscontained in stream 504. Rich solvent is flashed with vapor to a secondextractive distillation column that produces a high purity 1,3-butadienestream as an overhead product. Liquid solvent from the flash and thesecond distillation column bottoms are routed to a primary solventrecovery column. Bottoms liquid is circulated back to the extractor andoverhead liquid is passed to a secondary solvent recovery or solventpolishing column. Vapor overhead from the recovery columns combines withrecycle butadiene product into the bottom of the extractor to increaseconcentration of 1,3-butadiene. The 1,3-butadiene product 502 can bewater washed to remove any trace solvent. In certain embodiments, theproduct purity (wt %) is 97-99.8, 97.5-99.7 or 98-99.6 of 1,3-butadiene;and 94-99, 94.5-98.5 or 95-98 of the 1,3-butadiene content (wt %) of thefeed is recovered. In addition to the solvent such as DMF, additivechemicals are blended with the solvent to enhance butadiene recovery. Inaddition, the extractive distillation column and primary solventrecovery columns are reboiled using high pressure steam (for instance,600 psig) and circulating hot oil from the aromatics extraction zone 620as heat exchange fluid.

A methyl tertiary butyl ether zone 510 is integrated to produce methyltertiary butyl ether 514 and a second C4 raffinate 516 from the first C4raffinate stream 504. In certain embodiments C4 Raffinate 1 504 issubjected to selective hydrogenation to selectively hydrogenate anyremaining dienes and prior to reacting isobutenes with methanol toproduce methyl tertiary butyl ether.

Purity specifications for recovery of a 1-butene product stream 522necessitate that the level of isobutylene in the second C4 raffinate 516be reduced. In general, the first C4 raffinate stream 504 containingmixed butanes and butenes, and including isobutylene, is passed to themethyl tertiary butyl ether zone 510. Methanol 512 is also added, whichreacts with isobutylene and produces methyl tertiary butyl ether 514.For instance, methyl tertiary butyl ether product and methanol areseparated in a series of fractionators, and routed to a second reactionstage. Methanol is removed with water wash and a final fractionationstage. Recovered methanol is recycled to the fixed bed downflowdehydrogenation reactors. In certain embodiments described below withrespect to FIG. 14, additional isobutylene can be introduced to themethyl tertiary butyl ether zone 510, for instance, derived from ametathesis conversion unit.

In operation of one embodiment of the methyl tertiary butyl ether zone510, the raffinate stream 504, contains 35-45%, 37-42.5%, 38-41% or39-40% isobutylene by weight. This component is removed from the C4raffinate 516 to attain requisite purity specifications, for instance,greater than or equal to 98 wt % for the 1-butene product stream 522from the butene-1 recovery zone 520. Methanol 512, in certainembodiments high purity methanol having a purity level of greater thanor equal to 98 wt % from outside battery limits, and the isobutylenecontained in the raffinate stream 504 and in certain embodimentsisobutylene 544 from metathesis (shown in dashed lines as an optionalfeed), react in a primary reactor. In certain embodiments the primaryreactor is a fixed bed downflow dehydrogenation reactor and operates forisobutylene conversion in the range of about 70-95%, 75-95%, 85-95% or90-95% on a weight basis. Effluent from the primary reactor is routed toa reaction column where reactions are completed. In certain embodiments,exothermic heat of the reaction column and the primary reactor canoptionally be used to supplement the column reboiler along with providedsteam. The reaction column bottoms contains methyl tertiary butyl ether,trace amounts, for instance, less than 2%, of unreacted methanol, andheavy products produced in the primary reactor and reaction column.Reaction column overhead contains unreacted methanol and non-reactive C4raffinate. This stream is water washed to remove unreacted methanol andis passed to the 1-butene recovery zone 520 as the C4 raffinate 516.Recovered methanol is removed from the wash water in a methanol recoverycolumn and recycled to the primary reactor.

The C4 raffinate stream 516 from the methyl tertiary butyl ether zone510 is passed to a separation zone 520 for butene-1 recovery. In certainembodiments, upstream of the methyl tertiary butyl ether zone 510, orbetween the methyl tertiary butyl ether zone 510 and separation zone 520for butene-1 recovery, a selective hydrogenation zone can also beincluded (not shown). For instance, in certain embodiments, raffinatefrom the methyl tertiary butyl ether zone 510 is selectivelyhydrogenated in a selective hydrogenation unit to produce butene-1.Other co-monomers and paraffins are also co-produced. The selectivehydrogenation zone operates in the presence of an effective amount ofhydrogen obtained from recycle within the selective hydrogenation zoneand make-up hydrogen; in certain embodiments, all or a portion of themake-up hydrogen for the selective hydrogenation zone is derived fromthe steam cracker hydrogen stream 210 from the olefins recovery train270. For instance, a suitable selective hydrogenation zone can include,but is not limited to, systems based on technology commerciallyavailable from Axens, IFP Group Technologies, FR; Haldor Topsoe A/S, DK;Clariant International Ltd, CH; Chicago Bridge & Iron Company N.V.(CB&I), NL; Honeywell UOP, US; or Shell Global Solutions, US.

For selective recovery of a 1-butene product stream 522, and to recovera recycle stream 524 that is routed to the mixed feed steam crackingzone 230, and/or in certain embodiments described herein routed to ametathesis zone, one or more separation steps are used. For example,1-butene can be recovered using two separation columns, where the firstcolumn recovers olefins from the paraffins and the second columnseparates 1-butene from the mixture including 2-butene, which is blendedwith the paraffins from the first column and recycled to the steamcracker as a recycle stream 524.

In certain embodiments, the C4 raffinate stream 516 from the methyltertiary butyl ether zone 510 is passed to a first splitter, from whichfrom isobutane, 1-butene, and n-butane are separated from heavier C4components. Isobutane, 1-butene, and n-butane are recovered as overhead,condensed in an air cooler and sent to a second splitter. Bottoms fromthe first splitter, which contains primarily cis- and trans-2-butene canbe added to the recycle stream 524, or in certain embodiments describedherein passed to a metathesis unit. In certain arrangements, the firstsplitter overhead enters the mid-point of the second splitter. Isobutaneproduct 526 can optionally be recovered in the overhead (shown in dashedlines), 1-butene product 522 is recovered as a sidecut, and n-butane isrecovered as the bottoms stream. Bottoms from both splitters isrecovered as all or a portion of recycle stream 524.

The raw pyrolysis gasoline streams 234 and 254 from the steam crackersare treated and separated into treated naphtha and other fractions. Incertain embodiments, all, a substantial portion or a significant portionof the pyrolysis gasoline streams 234 and 254 are passed to the py-gashydrotreating zone 600. The raw pyrolysis gasoline streams 234 and 254are processed in a py-gas hydrotreating zone 600 in the presence of aneffective amount of hydrogen obtained from recycle within the py-gashydrotreating zone 600 and make-up hydrogen 602. Effluent fuel gas isrecovered and, for instance, passed to a fuel gas system. In certainembodiments, all or a portion of the make-up hydrogen 602 is derivedfrom the steam cracker hydrogen stream 210 from the olefins recoverytrain 270. For instance, a suitable py-gas hydrotreating zone 600 caninclude, but is not limited to, systems based on technology commerciallyavailable from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US;Axens, IFP Group Technologies, FR; Haldor Topsoe A/S, DK; or ChicagoBridge & Iron Company N.V. (CB&I), NL.

The py-gas hydrotreating zone 600 is operated under conditions, andutilizes catalyst(s), that can be varied over a relatively wide range.These conditions and catalyst(s) are selected for effectivehydrogenation for saturation of certain olefin and diolefin compounds,and if necessary for hydrotreating to remove sulfur and/or nitrogencontaining compounds. In certain embodiments, this is carried out in atleast two catalytic stages, although other reactor configurations can beutilized. Accordingly, py-gas hydrotreating zone 600 subjects thepyrolysis gasoline streams 234 and 254 to hydrogenation to producehydrotreated pyrolysis gasoline 604 effective as feed to the aromaticsextraction zone 620. Effluent off-gases are recovered from the py-gashydrotreating zone 600 and are passed to the olefins recovery train, thesaturated gas plant as part of the other gases stream 156, and/ordirectly to a fuel gas system. Liquefied petroleum gas can be recoveredfrom the py-gas hydrotreating zone 600 and routed to the mixed feedsteam cracking zone, the olefins recovery train and/or the saturated gasplant.

In the py-gas hydrotreating zone 600, diolefins in the feed and olefinsin the C6+ portion of the feed are saturated to produce a naphtha stream604, a C5+ feed to the aromatics extraction zone. In certainembodiments, a depentanizing step associated with the py-gashydrotreating zone 600 separates all or a portion of the C5s, forinstance, as additional feed 606 to the mixed feed steam cracking zone230 and/or as feed to a metathesis unit 530 (as shown, for instance, inFIG. 4, FIG. 6 or FIG. 14). In other embodiments, a depentanizing stepassociated with the aromatics extraction zone 620 separates all or aportion of the C5s from the hydrotreated naphtha stream 604, forinstance, as additional feed to the mixed feed steam cracking zone 230and/or as feed to a metathesis unit 530.

In certain embodiments, pyrolysis gasoline is processed in a firstreaction stage for hydrogenation and stabilization. Diolefins aresaturated selectively in the first reaction stage, and remaining olefinsare saturated in the second reaction stage along with converting feedsulfur into hydrogen sulfide. The pyrolysis gasoline can be treated in acold hydrotreating unit, therefore reducing the level of aromaticssaturation.

In an example of an effective py-gas hydrotreating zone 600, rawpyrolysis gasoline is passed through a coalescer before entering a feedsurge drum. The first stage reactor operates in mixed phase andselectively hydrogenates diolefins to mono-olefins and unsaturatedaromatics to side-chain saturated aromatics. Pd-based catalyst materialsare effective. Two parallel first-stage reactors can be used in certainembodiments to allow for regeneration in a continuous process withoutshutdown. In certain embodiments, the first-stage reactor contains threecatalyst beds with cooled first stage separator liquid recycled asquench material between each bed. First-stage effluent is stabilized andseparated in a column operating under slight vacuum to reducetemperature. In certain embodiments C5 from the C6+ is drawn, followedby a deoctanizer to remove C9+ and produce a C6-C8 heart naphtha cut.The column operates under slight vacuum to limit temperature. The firststage product is stripped to remove hydrogen, H₂S, and other light ends.In certain embodiments, the stripped first stage product is depentanizedto remove cracked C5, for instance, as feed to a metathesis unit. Asecond stage reactor operates in vapor phase and removes sulfur andsaturates olefins. The second stage product is stripped to removehydrogen, H₂S, and other light ends. In certain embodiments, bothreactors are multi-bed and use product recycle to control reactortemperature rise.

In certain embodiments, the first reaction stage of the py-gashydrotreating zone 600 operating conditions include:

a reactor inlet temperature (° C.) in the range of from about 80-135,80-125, 80-115, 95-135, 95-125, 95-115, 100-135, 100-125, 100-115 or107-111;

a reactor outlet temperature (° C.) in the range of from about 145-230,145-206, 145-200, 165-230, 165-206, 165-200, 175-230, 175-206, 175-200or 184-188;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 75-125, 75-115,75-110, 90-125, 90-115, 90-110, 95-125, 95-115, 95-110 or 99-104;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 124-195, 124-180, 124-170, 140-195, 140-180, 140-170,150-195, 150-180, 150-170 or 158-163;

a reaction inlet pressure (barg) in the range of from about 25-40,25-35, 25-33, 28-40, 28-35, 28-33, 30-40, 30-35 or 30-33;

a reaction outlet pressure (barg) in the range of from about 23-35,23-33, 23-31, 25-35, 25-33, 25-31, 28-35, 28-33 or −28-31;

a hydrogen partial pressure (barg) (outlet) in the range of from about15-25, 15-22, 15-21, 18-25, 18-22, 18-21, 19-25 or 19-22;

a hydrogen treat gas feed rate (SLt/Lt) up to about 180, 165 or 156, incertain embodiments from about 120-180, 120-165, 120-156, 134-180,134-165, 134-156, 140-180, 140-165 or 140-156;

a liquid quench feed ratio (Lt quench/Lt feed) up to about 0.8, 0.7, 0.6or 0.5, and in certain embodiments in the range of from about 0.35-0.6,0.35-0.55, 0.35-0.5, 0.4-0.6, 0.4-0.55, 0.4-0.5, 0.45-0.6, 0.45-0.55 or0.45-0.5; and

a make-up hydrogen feed rate (SLt/Lt) up to about 60, 55, 47 or 45, incertain embodiments from about 34-55, 34-47, 34-45, 40-55, 40-47, 40-45,42-55, 42-47 or 42-45.

In certain embodiments, the second reaction stage of the py-gashydrotreating zone 600 operating conditions include:

a reactor inlet temperature (° C.) in the range of from about 225-350,225-318, 225-303, 255-350, 255-318, 255-303, 270-350, 270-318, 270-303or 285-291;

a reactor outlet temperature (° C.) in the range of from about 289-445,289-405, 289-386, 328-445, 328-405, 328-386, 345-445, 345-405, 345-386or 364-370;

a start of run (SOR) reaction temperature (° C.), as a weighted averagebed temperature (WABT), in the range of from about 217-336, 217-306,217-291, 245-336, 245-306, 245-291, 260-336, 260-306, 260-291 or274-280;

an end of run (EOR) reaction temperature (° C.), as a WABT, in the rangeof from about 325-416, 325-380, 325-362, 305-416, 305-380, 305-362,325-416, 325-380, 325-362 or 340-346;

a reaction inlet pressure (barg) in the range of from about 25-37,25-34, 25-32, 28-37, 28-34, 28-32, 29-37, 29-34 or 29-32;

a reaction outlet pressure (barg) in the range of from about 23-35,23-32, 23-30, 26-35, 26-32, 26-30, 28-35, 28-32 or 28-30;

a hydrogen partial pressure (barg) (outlet) in the range of from about6-10, 6-9, 7-10 or 7-9;

a hydrogen treat gas feed rate (SLt/Lt) up to about 135, 126, 116 or110, in certain embodiments from about 84-126, 84-116, 84-110, 95-126,95-116, 95-110, 100-126, 100-116 or 100-110; and

a make-up hydrogen feed rate (SLt/Lt) up to about 30, 27 or 24, incertain embodiments from about 18-30, 18-27, 18-24, 21-30, 21-27, 21-24,22-30, 22-27 or 22-24.

An effective quantity of catalyst possessing selective hydrogenationfunctionality is provided, which generally contain one or more activemetal component of metals or metal compounds (oxides or sulfides)selected from Co, Mo, Pt, Pd, Fe, or Ni. The active metal component istypically deposited or otherwise incorporated on a support, such asamorphous alumina, amorphous silica alumina, zeolites, or combinationsthereof. Exemplary selective hydrogenation catalyst predominantly use Pdas the active metal component on alumina support, including thosecommercially available under the trade name Olemax® 600 and Olemax® 601.Effective liquid hourly space velocity values (h⁻¹), on a fresh feedbasis relative to the first stage pyrolysis gasoline reactor catalyst,are in the range of from about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0,0.3-5.0, 0.3-2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0 or 0.9-1.44. Suitablecatalysts used in the first stage pyrolysis gasoline reactor have anexpected lifetime in the range of about 18-30, 22-30, 18-26 or 22-26months.

An effective quantity of second stage pyrolysis gasoline reactorcatalyst is provided, including those having hydrogenation functionalityand which generally contain one or more active metal component of metalsor metal compounds (oxides or sulfides) selected from the Periodic Tableof the Elements IUPAC Groups 6-10. In certain embodiments, the activemetal component is one or more of Co, Ni, W and Mo. The active metalcomponent is typically deposited or otherwise incorporated on a support,such as amorphous alumina, amorphous silica alumina, zeolites, orcombinations thereof. In certain embodiments, the catalyst used in thefirst stage pyrolysis gasoline reactor includes one or more catalystselected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo. Combinations of one ormore of Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo, can also be used. For example,a combination of catalyst particles commercially available under thetrade names Olemax® 806 and Olemax® 807 can be used, with active metalcomponents of Co and Ni/Mo. The combinations can be composed ofdifferent particles containing a single active metal species, orparticles containing multiple active species. Effective liquid hourlyspace velocity values (h⁻¹), on a fresh feed basis relative to the firststage pyrolysis gasoline reactor catalyst, are in the range of fromabout 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5-10.0,0.5-5.0, 0.5-2.0 or 0.8-1.2. Suitable catalysts used in the second stagepyrolysis gasoline reactor have an expected lifetime in the range ofabout 18-30, 22-30, 18-26 or 22-26 months.

Hydrotreated pyrolysis gasoline 604 is routed to the aromaticsextraction zone 620. In certain embodiments to maximize production ofpetrochemicals, all, a substantial portion or a significant portion ofthe hydrotreated pyrolysis gasoline 604 is passed to the aromaticsextraction zone 620. In modes of operation in which production ofgasoline is the objective some of the hydrotreated pyrolysis gasoline604 is passed to a gasoline pool (not shown).

The aromatics extraction zone 620 includes, for instance, one or moreextractive distillation units, and operates to separate the hydrotreatedpyrolysis gasoline into high-purity benzene, toluene, xylenes and C9aromatics. As depicted in FIG. 13, a benzene stream 624, a mixed xylenesstream 626 and a raffinate stream 646 are recovered from the aromaticsextraction zone 620, with the raffinate stream 646 routed to the mixedfeed steam cracking zone 230 as additional feed. In addition, a toluenestream 636 and C9+ aromatics stream 638 are passed from the aromaticsextraction zone 620 to a toluene and C9+ transalkylation zone 630 forproduction of additional benzene and xylenes, recycled as stream 640 tothe aromatics extraction zone 620. In certain embodiments ethylbenzenecan be recovered (not shown). Heavy aromatics 642 are also recoveredfrom the aromatics extraction zone 620.

In certain embodiments of operation of the aromatics extraction zone620, aromatics are separated from the feed by extractive distillationusing, for instance, n-formylmorpholine (NFM), as an extractive solvent.Benzene, toluene, mixed xylenes and C9+ aromatics are separated viadistillation. Benzene and mixed xylenes are recovered as product streams624 and 626, and toluene 636 and C9+ aromatics 638 are sent to thetoluene and C9+ transalkylation zone 630. The transalkylation zoneproduct stream 640 containing benzene and mixed xylenes is returned tothe recovery section of the aromatics extraction zone 620. A paraffinicraffinate stream 646 is recycled as feed to the mixed feed steamcracking zone 230. In certain embodiments, the paraffinic raffinatestream 646 is in direct fluid communication with the mixed feed steamcracking zone 230, that is, the stream is not subject to furthercatalytic processing prior to the steam cracking step.

Selection of solvent, operating conditions, and the mechanism ofcontacting the solvent and feed permit control over the level ofaromatic extraction. For instance, suitable solvents includen-formylmorpholine, furfural, N-methyl-2-pyrrolidone, dimethylformamide,dimethylsulfoxide, phenol, nitrobenzene, sulfolanes, acetonitrile,furfural, or glycols, and can be provided in a solvent to oil ratio ofup to about 20:1, in certain embodiments up to about 4:1, and in furtherembodiments up to about 2:1. Suitable glycols include diethylene glycol,ethylene glycol, triethylene glycol, tetraethylene glycol anddipropylene glycol. The extraction solvent can be a pure glycol or aglycol diluted with from about 2-10 wt % water. Suitable sulfolanesinclude hydrocarbon-substituted sulfolanes (e.g., 3-methyl sulfolane),hydroxy sulfolanes (e.g., 3-sulfolanol and 3-methyl-4-sulfolanol),sulfolanyl ethers (e.g., methyl-3-sulfolanyl ether), and sulfolanylesters (e.g., 3-sulfolanyl acetate).

The aromatic separation apparatus can operate at a temperature in therange of from about 40-200, 40-150, 60-200, 60-150, 86-200 or 80-150° C.The operating pressure of the aromatic separation apparatus can be inthe range of from about 1-20, 1-16, 3-20, 3-16, 5-20 or 5-16 barg. Typesof apparatus useful as the aromatic separation apparatus in certainembodiments of the system and process described herein includeextractive distillation columns.

In one embodiment of operation of the aromatics extraction zone 620, thefeed contains primarily C6+ components, and is fractionated into a“heart cut” of C6-C8, and a heavy C9+ fraction. The C6-C8 cut is routedto the extractive distillation system where aromatics are separated fromnon-aromatics (saturates) via solvent distillation. The raffinate(non-aromatics) from the C6-C8 is removed and recycled back to thecracking complex as a feedstock. The aromatics are soluble in thesolvent and are carried from the bottom of the extractive distillationcolumn to the solvent stripper where they are stripped from the solvent,to recover aromatics extract and lean solvent which is recycled back tothe extractive distillation column. The mixed aromatics extract isrouted to a series of fractionation columns (a benzene column, a toluenecolumn and a xylene column) where each aromatic species is successivelyremoved, for instance, as benzene stream 624 and mixed xylenes stream626. The heavy C9+ fraction is further separated into C9 and C10+material. The toluene and C9 products are routed to the toluene and C9+transalkylation zone 630 where they are reacted to form additionalbenzene and mixed xylenes. This stream is recycled back to thefractionation portion of the aromatics extraction zone 620 to recoverthe benzene and mixed xylenes as well as to recycle the unconvertedtoluene and C9 aromatics. The transalkylation effluent does not requirere-extraction in the solvent distillation section and therefore isrouted to the inlet of the benzene column. In certain embodimentstoluene can be recycled to extinction, or approaching extinction. C10and heavier aromatics are removed as product 642. In certain embodimentsethylbenzene can be recovered.

The toluene and C9+ transalkylation zone 630 operates under conditionseffective to disproportionate toluene and C9+ aromatics into a mixedstream 640 containing benzene, mixed xylenes and heavy aromatics.Product ratio of benzene and xylene can be adjusted by selection ofcatalyst, feedstock and operating conditions. The transalkylation zone630 receives as feed the toluene stream 636 and the C9+ aromatics stream638 from the aromatics extraction zone 620. A small quantity of hydrogen632, in certain embodiments which is obtained all or in part from thehydrogen stream 210 derived from the olefins recovery zone 270, issupplied for transalkylation reactions. Side cracking reactions occurproducing fuel gas stream, for instance, passed to the fuel gas system,and LPG stream 634 that is recycled to mixed feed steam cracking zone. Asmall amount, such as 0.5-3 wt % of the total feed to the aromaticsextraction, of heavy aromatics are produced due to condensationreactions and are passed to the mixed stream 640 for recovery with otherheavy aromatics.

In operation of one embodiment of the toluene and C9+ transalkylationzone 630, toluene and C9 aromatics are reacted with hydrogen under mildconditions to form a mixture of C6-C11 aromatics. The mixed aromaticproduct stream 640 is recycled back to the aromatics extraction zone 620where the benzene and mixed xylenes are recovered as products. C7 and C9aromatics are recycled back as feed to the transalkylation zone 630, andthe C10+ fraction is removed from the aromatics extraction zone 620 asheavy aromatics stream 642. The disproportionation reactions occur inthe presence of an effective quantity of hydrogen. A minimal amount ofhydrogen is consumed by cracking reactions under reactor conditions.Purge gas is recycled back to the cracking complex for componentrecovery.

In certain embodiments, pyrolysis oil streams 236 and 256 can be blendedinto the fuel oil pool as a low sulfur component, and/or used as carbonblack feedstock. In additional embodiments, either or both of thepyrolysis oil streams 236 and 256 can be fractioned (not shown) intolight pyrolysis oil and heavy pyrolysis oil. For instance, lightpyrolysis oil can be blended with one or more of the middle distillatestreams, so that 0-100% of light pyrolysis oil derived from either orboth of the pyrolysis oil streams 236 and 256 is processed to producediesel fuel product and/or additional feed to the mixed feed steamcracking zone 230. In another embodiment 0-100% of light pyrolysis oilderived from either or both of the pyrolysis oil streams 236, 256 can beprocessed in the vacuum gas oil hydroprocessing zone. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of light pyrolysis oil can be processed in the delayedcoking zone 900. Heavy pyrolysis oil can be blended into the fuel oilpool as a low sulfur component, and/or used as a carbon black feedstock.In further embodiments, 0-100% of light pyrolysis oil and/or 0-100% ofheavy pyrolysis oil derived from either or both of the pyrolysis oilstreams 236, 256 can be processed in the delayed coking unit 900. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the pyrolysis oil streams 236, 256 (light andheavy) can be processed in the delayed coking zone 900.

FIG. 14 depicts embodiments including integration of a metathesis zone530. The process of FIG. 14 operates according to the description withrespect to FIGS. 7, 8 and 13, or any of the other embodiments herein, inall other aspects. For instance, a suitable metathesis zone 530 caninclude, but is not limited to, systems based on technology commerciallyavailable from Chicago Bridge & Iron Company N.V. (CB&I), NL.

Feedstocks to the metathesis zone 530 include: a portion 536 of theethylene product 202; a C4 Raffinate-3 stream 532 from the 1-butenerecovery zone 520, and the olefinic C5 cut 606 from the py-gashydrotreating zone 600. The C4 Raffinate-3 stream 532 is 0-100% of thetotal C4 Raffinate-3 from the 1-butene recovery zone 520; any remainingportion 524 can be recycled to the mixed feed steam cracking zone 230.Products from the metathesis zone 530 include a propylene product stream534 and a stream 542, having a mixture of mostly saturated C4/C5 from ametathesis unit that is recycled to the mixed feed steam cracking zone.In certain embodiments, isobutylene 544 can also be recovered (shown indashed lines) and routed to the methyl tertiary butyl ether zone 510. Inembodiments that operate without separation of isobutylene, it isincluded within stream 542.

In an example of a metathesis zone 530 used in the integrated processherein, the C4 Raffinate-3 stream 532 from the separation zone 520 andthe C5 olefins stream 606 from the py-gas hydrotreating zone 600 (or thearomatics extraction zone) pass through a guard bed to remove t-butylcatechol and are mixed with a molar excess of fresh and recycledethylene. The reactor feed passes through another guard bed to removeother trace contaminants, is heated in a furnace and enters thedisproportionation (metathesis) reactor, where propylene is formed. Thereactions reach equilibrium conversion. The metathesis reactor effluentcontains a mixture of propylene, ethylene, and butenes/butanes, and someC5 and heavier components from by-product reactions. C4 olefinsisomerize in the disproportionation reactor and react with ethylene toform additional propylene. In certain embodiments, disproportionation ofC5 olefins yields isobutylene by-product for production of additionalMTBE. Cooled reactor effluent enters a deethylenizer, which recyclesoverhead ethylene to the disproportionation reactor. Deethylenizerbottoms are passed to a depropylenizer, which recovers grade propyleneproduct as overhead. Propylene product purity is >99.5 mol % (polymergrade). In certain embodiments depropylenizer bottoms enter adeisobutylenizer, which recovers isobutylene as overhead for additionalfeedstock to the MTBE zone 510. Deisobutylenizer bottoms are mixed witha recycle stream to dilute the olefin concentration, the mixture isheated and mixed with hydrogen, and routed to a total hydrogenationreactor, which saturates any remaining C4/C5 or heavier olefins andthereby enhances light olefin yields. Cooled reactor effluent isrecycled as feedstock to the mixed feed steam cracking zone 230.

FIG. 15 depicts embodiments in which kerosene sweetening is in anoptional unit, that is, the first middle distillate fraction 116 can berouted either through the kerosene sweetening zone 170 or routed to thedistillate hydrotreating zone 180. The process of FIG. 15 operatesaccording to the description with respect to FIGS. 7 and 13, or any ofthe other embodiments herein, in all other aspects.

During periods in which maximizing the fuel fraction 172 is desired, thefirst middle distillate fraction 116 can be routed to the kerosenesweetening zone 170. During periods in which the feedstock to the mixedfeed steam cracking zone 230 is to be maximized, the first middledistillate fraction 116 can be routed to the distillate hydrotreatingzone 180, so as to produce additional hydrotreated naphtha 184. Inadditional alternative embodiments, the first middle distillate fraction116 can be divided (on a volume or weight basis, for example, with adiverter) so that a portion is passed to the distillate hydrotreatingzone 180 and the remaining portion is passed to the kerosene sweeteningzone 170.

FIG. 16 depicts embodiments in which kerosene sweetening is eliminated.Accordingly, in the embodiments of FIG. 16, two middle distillatefractions are used. In this embodiment, a first middle distillatefraction 124 is routed to the distillate hydrotreating zone 180, and asecond middle distillate fraction 134 may be similar to the third middledistillate fraction 126 described in other embodiments herein. In oneexample using the arrangement shown in FIG. 16, the first middledistillate fraction 124 contains kerosene range hydrocarbons and mediumAGO range hydrocarbons, and the second atmospheric distillation zonemiddle distillate fraction 134 contains heavy AGO range hydrocarbons. Inanother example using the arrangement shown in FIG. 16, the first middledistillate fraction 124 contains kerosene range hydrocarbons and aportion of medium AGO range hydrocarbons and the second middledistillate fraction 134 contains a portion of medium AGO rangehydrocarbons and heavy AGO range hydrocarbons. The process of FIG. 16operates according to the description with respect to FIGS. 7 and 13, orany of the other embodiments herein, in all other aspects.

Advantageously, process dynamics of the configurations and theintegration of units and streams attain a very high level of integrationof utility streams between the mixed feed steam cracking and otherprocess units, result in increased efficiencies and reduced overalloperating costs. For instance, the hydrogen can be tightly integrated sothat the net hydrogen demand from outside of the battery limits isminimized or even eliminated. In certain embodiments, the overallhydrogen utilization from outside of the battery limits is less thanabout 40, 30, 15, 10 or 5 wt % hydrogen based on the total hydrogenrequired by the hydrogen users in the integrated process. Hydrogen isrecovered from the olefins recovery train, and is supplied to thehydrogen users in the system, including the diesel hydrotreater, the gasoil hydroprocessing zone, the vacuum residue hydroprocessing zone, thepy-gas hydrotreater, and transalkylation, so as to derive most or all ofthe utility hydrogen from within the battery limits. In certainembodiments there is zero external hydrogen use, in which make-uphydrogen is only required to initiate the operations; when the reactionsreach equilibrium, the hydrogen derived from the mixed feed steamcracking and gas oil steam cracking products provides sufficienthydrogen to maintain the hydrogen requirements of the hydrogen users inthe integrated process. In further embodiments, there is a net hydrogengain, so that hydrogen can be added, for instance, to the fuel gas thatis used to operate the various heating units within the integratedprocess.

Furthermore, the integrated process described herein offers usefuloutlets for the off-gases and light ends from the hydroprocessing units.For instance, the stream 156 that is passed to the saturated gas plant150 of the crude complex 100 can contain off-gases and light ends fromthe hydroprocessing units, such as the diesel hydrotreating zone 180,the gas oil hydrotreating zone 300 and/or from the py-gas hydrotreatingzone 600. In other embodiments, in combination with or as an alternativeto the passing these off-gases and light ends to stream 156, all or aportion can be routed to the mixed feed steam cracking unit 230. Forinstance, C2s can be separated from the mixture of methane, hydrogen andC2s using a cold distillation section (“cold box”) including cryogenicdistillation/separation operations, which can be integrated with any orall of the mixed feed steam cracking unit 230, the saturated gas plant150 and/or the olefins recovery zone 270. Methane and hydrogen can bepassed to a fuel gas system or to an appropriate section of the olefinsrecovery zone 270, such as the hydrogen purification system. In stillfurther embodiments, in combination with or as an alternative to thepassing these off-gases and light ends to stream 156 and/or routing themto the mixed feed steam cracking unit 230, all or a portion can berouted to an appropriate section of the olefins recovery zone 270, suchas the depropanizer, or combining the gases with the depropanizeroverheads.

The unique configurations presented herein set forth a level ofintegration, of streams and units that allows the use of gas oil steamcrackers in an economically efficient manner. The configurations supportand enhance chemical conversion using integrated processes with crudeoil as a feed. Hence, not only do these configurations permit lowercapital expenditure relative to conventional approaches of chemicalproduction from fuels or refinery by-products, but it also exhibits aneconomical use of the UCO cracker (through the integration).Accordingly, despite the use of crude oil as the feed, the processesherein are comparable to other options currently common in the industrysuch as ethane crackers that benefit from availability of ethane as afeed.

Embodiments described herein provide the ability to achieve a crude tochemical conversion ratio in the range of, for instance, up to 80, 50 or45 wt %, and in certain embodiments in the range of about 39-45 wt %. Incertain embodiments the chemical conversion ratio is at least about 39wt %, and in certain embodiments in the range of about 39-80, 39-50 or,39-45 wt %. It should be appreciated that this crude to chemicalsconversion ratio can vary depending on criteria such as feed, selectedtechnology, catalyst selection and operating conditions for theindividual unit operations.

In some embodiments, individual unit operations can include a controllerto monitor and adjust the product slate as desired. A controller candirect parameters within any of the individual unit operations theapparatus depending upon the desired operating conditions, which may,for example, be based on customer demand and/or market value. Acontroller can adjust or regulate valves, feeders or pumps associatedwith one or more unit operations based upon one or more signalsgenerated by operator data input and/or automatically retrieved data.

Such controllers provide a versatile unit having multiple modes ofoperation, which can respond to multiple inputs to increase theflexibility of the recovered product. The controller can be implementedusing one or more computer systems which can be, for example, ageneral-purpose computer. Alternatively, the computer system can includespecially-programmed, special-purpose hardware, for example, anapplication-specific integrated circuit (ASIC) or controllers intendedfor a particular unit operation within a refinery.

The computer system can include one or more processors typicallyconnected to one or more memory devices, which can comprise, forexample, any one or more of a disk drive memory, a flash memory device,a RAM memory device, or other device for storing data. The memory istypically used for storing programs and data during operation of thesystem. For example, the memory can be used for storing historical datarelating to the parameters over a period of time, as well as operatingdata. Software, including programming code that implements embodimentsof the invention, can be stored on a computer readable and/or writeablenonvolatile recording medium, and then typically copied into memorywherein it can then be executed by one or more processors. Suchprogramming code can be written in any of a plurality of programminglanguages or combinations thereof.

Components of the computer system can be coupled by one or moreinterconnection mechanisms, which can include one or more busses, forinstance, between components that are integrated within a same device,and/or a network, for instance, between components that reside onseparate discrete devices. The interconnection mechanism typicallyenables communications, for instance, data and instructions, to beexchanged between components of the system.

The computer system can also include one or more input devices, forexample, a keyboard, mouse, trackball, microphone, touch screen, andother man-machine interface devices as well as one or more outputdevices, for example, a printing device, display screen, or speaker. Inaddition, the computer system can contain one or more interfaces thatcan connect the computer system to a communication network, in additionor as an alternative to the network that can be formed by one or more ofthe components of the system.

According to one or more embodiments of the processes described herein,the one or more input devices can include sensors and/or flow meters formeasuring any one or more parameters of the apparatus and/or unitoperations thereof. Alternatively, one or more of the sensors, flowmeters, pumps, or other components of the apparatus can be connected toa communication network that is operatively coupled to the computersystem. Any one or more of the above can be coupled to another computersystem or component to communicate with the computer system over one ormore communication networks. Such a configuration permits any sensor orsignal-generating device to be located at a significant distance fromthe computer system and/or allow any sensor to be located at asignificant distance from any subsystem and/or the controller, whilestill providing data therebetween. Such communication mechanisms can beaffected by utilizing any suitable technique including but not limitedto those utilizing wired networks and/or wireless networks andprotocols.

Although the computer system is described above by way of example as onetype of computer system upon which various aspects of the processesherein can be practiced, it should be appreciated that the invention isnot limited to being implemented in software, or on the computer systemas exemplarily described. Indeed, rather than implemented on, forexample, a general purpose computer system, the controller, orcomponents or subsections thereof, can alternatively be implemented as adedicated system or as a dedicated programmable logic controller (PLC)or in a distributed control system. Further, it should be appreciatedthat one or more features or aspects of the processes can be implementedin software, hardware or firmware, or any combination thereof. Forexample, one or more segments of an algorithm executable by a controllercan be performed in separate computers, which in turn, can be incommunication through one or more networks.

In some embodiments, one or more sensors and/or flow meters can beincluded at locations throughout the process, which are in communicationwith a manual operator or an automated control system to implement asuitable process modification in a programmable logic controlledprocess. In one embodiment, a process includes a controller which can beany suitable programmed or dedicated computer system, PLC, ordistributed control system. The flow rates of certain product streamscan be measured, and flow can be redirected as necessary to meet therequisite product slate.

Factors that can result in various adjustments or controls includecustomer demand of the various hydrocarbon products, market value of thevarious hydrocarbon products, feedstock properties such as API gravityor heteroatom content, and product quality (for instance, gasoline andmiddle distillate indicative properties such as octane number forgasoline and cetane number for middle distillates).

The disclosed processes and systems create new outlets for directconversion of crude oil, for instance, light crudes such as Arab ExtraLight (AXL) or Arab Light (AL) crude oil. Additionally, the disclosedprocesses and systems offer novel configurations that, compared to knownprocesses and systems, requires lower capital expenditure relative toconventional approaches of chemical production from fuels or refineryby-products and that utilize refining units and an integrated chemicalscomplex. The disclosed processes and systems substantially increase theproportion of crude oil that is converted to high purity chemicals thattraditionally command high market prices. Complications resulting fromadvancing the threshold of commercially proven process capacities areminimized or eliminated using the processes and systems describedherein.

The disclosed processes and systems utilize different commerciallyproven units arranged in novel configurations. These novelconfigurations enable production of refined products and petrochemicalproducts including olefins, aromatics, MTBE, and butadiene. Thedisclosed processes and systems allow chemicals producers to de-couplefrom fuel markets and have more freedom to increase chemical yields as afraction of crude rate, as compared to traditional chemical productionusing refinery intermediates or by-products as feedstock. Also, thedisclosed processes and systems substantially increase the proportion ofcrude oil that is converted to high purity chemicals that traditionallycommand high market prices.

The disclosed processes and systems provide alternatives for chemicalsproduction that have lower capital investment relative to conventionalroutes that utilize refining units and an integrated chemicals complex.Moreover, the disclosed processes and systems offer the flexibility ofsimultaneously producing fuel products and chemical products. The ratioof chemicals to residual fuels can be modulated by process operations toaddress changing fuels and chemical market opportunities. In certainembodiments, the process configurations are flexible to enableprocessing of crude oil, such as Arab Light or Arab Extra Light, toprovide superior production of chemical products, while minimizing theproduction of refined fuel products. The configurations offer theflexibility to structure operations to adjust the ratio ofpetrochemicals to refined products in order to achieve optimumoperations and allows shifting the production ratio of chemicals tofuels, thereby adjusting to market conditions.

For example, in vacuum gas oil hydroprocessing, as severity increases,the yield of UCO (or hydrotreated gas oil) decreases as the naphthayield increases, although for the most part the distillate yield doeschange as much because wild naphtha product is the result of distillatecracking. The UCO product is chemically restructured through ringopening reactions to become much more paraffinic in nature, and remainsa gas oil boiling range product. By modulating severity of vacuum gasoil hydroprocessing, the shift is between naphtha and UCO (orhydrotreated gas oil) relative product rates. The olefin yield ofnaphtha in the steam cracker is superior to UCO (or hydrotreated gasoil); while the heavy product yield (mixed C4s and pyrolysis gasoline)from UCO (or hydrotreated gas oil) is superior to naphtha. Therefore, akey advantage of modulating the vacuum gas oil hydroprocessingconversion is to economically and dynamically address changing marketconditions for olefin and aromatic products, which may swingdramatically.

Each of the processing units are operated at conditions typical for suchunits, which conditions can be varied based on the type of feed tomaximize, within the capability of the unit's design, the desiredproducts. Desired products can include fractions suitable as feedstockto the mixed feed steam cracking zone 230 or gas oil steam cracking zone250, or fractions suitable for use as fuel products. Likewise,processing units employ appropriate catalyst(s) depending upon the feedcharacteristics and the desired products. Certain embodiments of theseoperating conditions and catalysts are described herein, although itshall be appreciated that variations are well known in the art and arewithin the capabilities of those skilled in the art.

For the purpose of the simplified schematic illustrations anddescriptions herein, accompanying components that are conventional incrude centers, such as the numerous valves, temperature sensors,preheater(s), desalting operation(s), and the like are not shown.

In addition, accompanying components that are in conventionalhydroprocessing units such as, for example, hydrogen recyclesub-systems, bleed streams, spent catalyst discharge sub-systems, andcatalyst replacement sub-systems the like are not shown.

Further, accompanying components that are in conventional thermalcracking systems such as steam supplies, coke removal sub-systems,pyrolysis sections, convection sections and the like are not shown.

The method and system of the present invention have been described aboveand in the attached drawings; however, modifications will be apparent tothose of ordinary skill in the art and the scope of protection for theinvention is to be defined by the claims that follow.

The invention claimed is:
 1. An integrated system for producingpetrochemicals and fuel products comprising: an atmospheric distillationunit (ADU) operable to receive and separate a feed, and discharge afirst ADU fraction comprising naphtha, a second ADU fraction comprisingat least a portion of middle distillates from the feed, and a third ADUfraction comprising atmospheric residue; a vacuum distillation unit(VDU) operable to receive and separate the third ADU fraction, anddischarge a first VDU fraction comprising vacuum gas oil and a secondVDU fraction comprising vacuum residue; a delayed coking zone operableto receive and convert the second VDU fraction comprising vacuum residueinto a coker naphtha stream, a coker gas oil stream and petroleum coke;a distillate hydroproces sing (DHP) zone operable to receive and convertmiddle distillates from the second ADU fraction into a first DHPfraction and a second DHP fraction, wherein the first DHP fractioncomprises naphtha and the second DHP fraction is used for diesel fuelproduction; a gas oil hydroproces sing (GOHP) zone operable to receiveand treat vacuum gas oil from the first VDU fraction and the coker gasoil stream and produce a first GOHP fraction containing naphtha rangecomponents, and a second GOHP fraction containing heavy oil, which ishydrotreated gas oil or unconverted oil in the vacuum gas oil range; asteam cracking zone comprising (a) a mixed feed steam cracking (MFSC)zone operable to receive and thermally crack naphtha from the first ADUfraction and a C6-C9 non-aromatics raffinate stream derived from anaromatics extraction zone, and (b) a gas oil steam cracking (GOSC) zoneoperable to receive and thermally crack the second GOHP fraction,wherein the steam cracking zone is operable to produce a mixed productstream containing mixed C1-C4 paraffins and olefins, a pyrolysis gasstream, and a pyrolysis oil stream; a naphtha hydroproces sing zoneoperable to receive and treat the pyrolysis gas stream and produce ahydrotreated pyrolysis gas stream; and the aromatics extraction zoneoperable to receive and separate the hydrotreated pyrolysis gas streaminto one or more aromatic products streams, and the C6-C9 non-aromaticsraffinate stream.
 2. The system as in claim 1, further comprising acoker naphtha hydrotreater operable to receive and convert the cokernaphtha stream to into a hydrotreated coker naphtha effluent, whereinthe aromatics extraction zone is operable to receive and separatearomatics from the hydrotreated coker naphtha effluent.
 3. The system asin claim 2, wherein the coker naphtha hydrotreater is operable toseparate C5s from hydrotreated coker naphtha effluent prior toseparation of aromatics in the aromatics extraction zone, and whereinthe MFSC zone is operable to receive C5s separated from hydrotreatedcoker naphtha.
 4. The system as in claim 1, wherein the delayed cokingzone is operable to receive the pyrolysis oil stream.
 5. The system asin claim 1, wherein pyrolysis oil comprises light pyrolysis oil andheavy pyrolysis oil, wherein the GOHP zone is operable to receive lightpyrolysis oil, and wherein the delayed coking zone is operable toreceive heavy pyrolysis oil.
 6. The system as in claim 1, wherein theMFSC zone is operable to receive and thermally crack naphtha from thefirst DHP fraction, naphtha from the first GOHP fraction, or bothnaphtha from the first DHP fraction and naphtha from the GOHP fraction.7. The system as in claim 1, wherein the naphtha hydrotreating zone isoperable to produce a C5s stream, and wherein the MFSC zone is operableto receive and thermally crack the C5s stream.
 8. The system as in claim1, wherein the ADU is further operable to receive and separate naphthafrom the first DHP fraction, naphtha from the GOHP fraction, or bothnaphtha from the first DHP fraction and naphtha from the GOHP fraction.9. The system as in claim 1, wherein the ADU is operable to separate afurther ADU fraction including heavy AGO that is heavier than the secondADU fraction and lighter than the third ADU fraction, and wherein theGOHP zone is operable to receive and convert the further ADU fraction.10. The system as in claim 1, wherein the ADU is operable to separate afurther ADU fraction including heavy AGO that is heavier than the secondADU fraction and lighter than the third ADU fraction, and wherein theGOSC zone is operable to receive and thermally crack the further ADUfraction.
 11. The system as in claim 1, wherein the ADU is operable toseparate a further ADU fraction including kerosene that is heavier thanthe first ADU fraction and lighter than the second ADU fraction, and thesystem further comprising a kerosene sweetening zone operable to receiveand treat the further ADU fraction.
 12. The system as in claim 11,wherein the ADU is operable to separate a further ADU fraction includingheavy AGO that is heavier than the second ADU fraction and lighter thanthe third ADU fraction, and wherein (a) the GOSC zone is operable toreceive and thermally crack the additional ADU fraction, or (b) the GOHPzone is operable to receive and convert the additional ADU fraction. 13.The system as in claim 1, further comprising: an olefins recovery trainoperable to receive and separate the mixed product into a fuel gasstream, an ethylene stream, a mixed C3s stream, and a mixed C4s stream,and a C4 distillation unit operable to receive and separate a portion ofC4s recovered from the mixed product stream into an olefinic stream anda non-olefinic stream.
 14. The system as in claim 13, wherein the MFSCzone is operable to receive and thermally crack the non-olefinic stream.15. The system as in claim 13, further comprising a mixed butanolsproduction zone operable to receive and convert a mixture of butenesfrom the C4 distillation unit into a mixed butanol product stream. 16.The system as in claim 13, further comprising a metathesis reaction zoneoperable to receive and convert all or a portion of the C5s stream intoa propylene stream, and a C4/C5 raffinate stream, and wherein the MFSCzone is operable to receive and thermally crack the C4/C5 raffinatestream.
 17. The system as in claim 13, wherein the naphtha hydrotreatingzone is operable to produce a C5s stream, and further comprising ametathesis reaction zone operable to receive and convert all or aportion of the C5s stream into a propylene stream, and a C4/C5 raffinatestream; and a mixed butanols production zone operable to receive andconvert a mixture of butenes from the C4 distillation unit into a mixedbutanol product stream and an alkanes stream; wherein the MFSC zone isoperable to receive and thermally crack the non-olefinic stream and theC4/C5 raffinate stream.